IESO_REP_0723
System Impact
Assessment
Report
LSG Bell Creek Complex Expansion
CONNECTION ASSESSMENT &
APPROVAL PROCESS
Final Report
CAA ID 2011-425
Applicant: Lake Shore Gold-Bell Creek Complex
Market Facilitation Department
October 25, 2011
System Impact Assessment Report
Document ID
ISO_REP_0723
Document Name
System Impact Assessment Report
Issue
1.0
Reason for Issue
Final
Effective Date
October 25, 2011
IESO_REP_0723
System Impact Assessment Report
CAA ID 2011-425
System Impact Assessment Report
LSG Bell Creek Complex Expansion
Acknowledgement
The IESO wishes to acknowledge the assistance of Hydro One in completing this assessment.
Disclaimers
IESO
This report has been prepared solely for the purpose of assessing whether the connection
applicant's proposed connection with the IESO-controlled grid would have an adverse impact on
the reliability of the integrated power system and whether the IESO should issue a notice of
conditional approval or disapproval of the proposed connection under Chapter 4, section 6 of the
Market Rules.
Conditional approval of the proposed connection is based on information provided to the IESO
by the connection applicant and Hydro One at the time the assessment was carried out. The IESO
assumes no responsibility for the accuracy or completeness of such information, including the
results of studies carried out by Hydro One at the request of the IESO. Furthermore, the
conditional approval is subject to further consideration due to changes to this information, or to
additional information that may become available after the conditional approval has been
granted.
If the connection applicant has engaged a consultant to perform connection assessment studies,
the connection applicant acknowledges that the IESO will be relying on such studies in
conducting its assessment and that the IESO assumes no responsibility for the accuracy or
completeness of such studies including, without limitation, any changes to IESO base case
models made by the consultant. The IESO reserves the right to repeat any or all connection
studies performed by the consultant if necessary to meet IESO requirements.
Conditional approval of the proposed connection means that there are no significant reliability
issues or concerns that would prevent connection of the proposed facility to the IESO-controlled
grid. However, the conditional approval does not ensure that a project will meet all connection
requirements. In addition, further issues or concerns may be identified by the transmitter(s)
during the detailed design phase that may require changes to equipment characteristics and/or
configuration to ensure compliance with physical or equipment limitations, or with the
Transmission System Code, before connection can be made.
This report has not been prepared for any other purpose and should not be used or relied upon by
any person for another purpose. This report has been prepared solely for use by the connection
applicant and the IESO in accordance with Chapter 4, section 6 of the Market Rules. The IESO
assumes no responsibility to any third party for any use, which it makes of this report. Any
liability which the IESO may have to the connection applicant in respect of this report is
governed by Chapter 1, section 13 of the Market Rules. In the event that the IESO provides a
draft of this report to the connection applicant, the connection applicant must be aware that the
IESO may revise drafts of this report at any time in its sole discretion without notice to the
connection applicant. Although the IESO will use its best efforts to advise you of any such
changes, it is the responsibility of the connection applicant to ensure that the most recent version
of this report is being used.
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System Impact Assessment Report
CAA ID 2011-425
HYDRO ONE
Special Notes and Limitations of Study Results
The results reported in this report are based on the information available to Hydro One, at the
time of the study, suitable for a System Impact Assessment of this transmission system
reinforcement proposal.
The short circuit and thermal loading levels have been computed based on the information
available at the time of the study. These levels may be higher or lower if the connection
information changes as a result of, but not limited to, subsequent design modifications or when
more accurate test measurement data is available.
This study does not assess the short circuit or thermal loading impact of the proposed facilities
on load and generation customers.
In this report, short circuit adequacy is assessed only for Hydro One circuit breakers. The short
circuit results are only for the purpose of assessing the capabilities of existing Hydro One circuit
breakers and identifying upgrades required to incorporate the proposed facilities. These results
should not be used in the design and engineering of any new or existing facilities. The necessary
data will be provided by Hydro One and discussed with any connection applicant upon request.
The ampacity ratings of Hydro One facilities are established based on assumptions used in Hydro
One for power system planning studies. The actual ampacity ratings during operations may be
determined in real-time and are based on actual system conditions, including ambient
temperature, wind speed and facility loading, and may be higher or lower than those stated in this
study.
The additional facilities or upgrades which are required to incorporate the proposed facilities
have been identified to the extent permitted by a System Impact Assessment under the current
IESO Connection Assessment and Approval process. Additional facility studies may be
necessary to confirm constructability and the time required for construction. Further studies at
more advanced stages of the project development may identify additional facilities that need to
be provided or that require upgrading.
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System Impact Assessment Report
Table of Contents
Table of Contents
Table of Contents ...................................................................................................... i
List of Figures ......................................................................................................... iii
List of Tables ........................................................................................................... iv
Executive Summary ................................................................................................. 1
SIA Findings.................................................................................................................. 1
IESO’s Requirements for Connection ............................................................................ 1
Notification of Conditional Approval ............................................................................... 3
1.
Project Description .......................................................................................... 4
2.
IESO’s General Requirements......................................................................... 5
2.1
2.2
Voltage .............................................................................................................. 5
Power Factor ..................................................................................................... 5
2.3
Protection Systems ............................................................................................ 5
2.4
Breaker Interrupting Time .................................................................................. 6
2.5
2.6
Fault Levels ....................................................................................................... 6
Under frequency Load Shedding (UFLS) ........................................................... 6
2.7
Telemetry .......................................................................................................... 7
2.8
Revenue Metering ............................................................................................. 7
2.9
2.10
Connection Equipment Design .......................................................................... 7
Restoration Participant Requirements ............................................................... 8
2.11
Reliability Standards .......................................................................................... 8
2.12
Facility Registration/Market Entry ...................................................................... 8
3.
Data Verification ............................................................................................. 10
4.
Review of Existing System ............................................................................ 12
4.1
4.2
5.
Existing System ............................................................................................... 12
Historical data .................................................................................................. 13
System Impact Assessment Studies ............................................................ 15
5.1
Study Criteria ................................................................................................... 15
5.2
Study Assumptions .......................................................................................... 18
5.2.1
Existing/Committed Facilities ............................................................. 18
5.2.2
Load Forecast .................................................................................... 19
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5.2.3
5.3
Table of Contents
Line ratings ........................................................................................ 19
Contingency Based Assessment ..................................................................... 20
5.3.1
Load Flow Scenario ........................................................................... 20
5.3.2
Local Area Contingencies .................................................................. 20
5.3.3
Equipment Loadings .......................................................................... 21
5.3.4
Voltage Assessment .......................................................................... 21
5.3.5
Motor Start Study ............................................................................... 22
5.3.6
Steady State Voltage Stability ............................................................ 22
6.
Fault Levels..................................................................................................... 24
7.
References ...................................................................................................... 25
Appendix A: Equipment Loading Results ........................................................... 26
Appendix B: System Voltage Assessment Results ............................................ 38
Appendix C: Motor Start Studies .......................................................................... 47
Appendix D: Voltage Stability Analysis ............................................................... 48
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List of Figures
List of Figures
Figure 1: LSG Bell Creek Complex Single Line Diagram ..................................................................... 4
Figure 2: Transmission System in the vicinity of the project ............................................................... 12
Figure 3: Porcupine 115 kV bus voltage duration curve ...................................................................... 13
Figure 4: D501 500 kV line flow measured at Porcupine TS. ........................................................... 13
Figure 5: P502X 500 kV line flow measured at Porcupine TS ............................................................ 14
Figure 6: PV Curve-pre and post contingency voltages at Bell Creek 115 kV bus.............................. 22
Figure 7: PV Curve- pre and post contingency voltages at Porcupine 115 kV bus.............................. 23
Figure D 1: PV Curves- Pre and Post contingency voltages in the vicinity of the project ................... 48
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System Impact Assessment Report
List of Tables
List of Tables
Table 1: Average voltages at main stations
14
Table 2: Flows on circuits
14
Table 3: Generation output
14
Table 4: Static Load Models for Simulations
15
Table 5: Existing/Committed facilities in the vicinity of the project
18
Table 6: Loads in Porcupine area.
19
Table 7: Line Ratings
19
Table 8: Voltage at main buses near LSG Bell Creek complex substation
20
Table 9: Fault Level Assessments
24
Table A 1: Thermal Loading Assessment-with all elements in service Results................................... 26
Table A 2: Thermal Loading Assessment-Following the loss of Porcupine SVC ............................... 27
Table A 3: Thermal Loading Assessment-Following the loss of 115 kV P13T circuit........................ 28
Table A 4: Thermal Loading Assessment-Following the loss of 115 kV P15T circuit........................ 29
Table A 5: Thermal Loading Assessment-Following the loss of 115 kV H6T circuit ......................... 30
Table A 6: Thermal Loading Assessment-Following the loss of 115 kV H7T circuit ......................... 31
Table A 7: Thermal Loading Assessment-Following the loss of 230 kV P91G circuit ....................... 32
Table A 8: Thermal Loading Assessment-Following the loss of Porcupine 115 kV Transformer T3 . 33
Table A 9: Thermal Loading Assessment-Following the loss of Porcupine 115 kV transformer T4 .. 34
Table A 10: Transformer Loading-With all elements in service .......................................................... 35
Table A 11: Transformer Loading-Following the loss of Porcupine SVC........................................... 35
Table A 12: Transformer Loading-Following the loss of 115 kV P13T circuit ................................... 35
Table A 13: Transformer Loading-Following the loss of 115 kV P15T circuit ................................... 35
Table A 14: Transformer Loading-Following the loss of 115 kV H6T circuit .................................... 36
Table A 15: Transformer Loading-Following the loss of 115 kV H7T circuit .................................... 36
Table A 16: Transformer Loading-Following the loss of 230 kV P91G circuit .................................. 36
Table A 17: Transformer Loading-Following the loss of Porcupine 115 kV transformer T3.............. 36
Table A 18: Transformer Loading-Following the loss of Porcupine 115 kV transformer T4.............. 37
Table B 1: System Voltage Assessment Results-With all elements in service .................................... 38
Table B 2: System Voltage Assessment Results-Following the loss of Porcupine SVC ..................... 39
Table B 3: System Voltage Assessment Results-Following the loss of 115 kV P13T circuit ............. 40
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List of Tables
Table B 4: System Voltage Assessment Results-Following the loss of 115 kV P15T circuit ............. 41
Table B 5: System Voltage Assessment Results-Following the loss of 115 kV H6T circuit ............... 42
Table B 6: System Voltage Assessment Results-Following the loss of 115 kV H7T circuit ............... 43
Table B 7: System Voltage Assessment Results-Following the loss of 230 kV P91G circuit ............. 44
Table B 8: System Voltage Assessment Results-Following the loss of Porcupine 115 kV T/F T3 ..... 45
Table B 9: System Voltage Assessment Results-Following the loss of Porcupine 115 kV T/F T4 ..... 46
Table C 1: Motor start study................................................................................................................. 47
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Executive Summary
Executive Summary
This System Impact Assessment examined the effects of connecting Lake Shore Gold (LSG) Bell
Creek Complex Expansion (the project) geographically located in Northeastern Ontario, proposed by
LSG-Bell Creek Complex (the connection applicant), on the reliability of IESO controlled grid. The
project will supply a load of 40 MW to the existing LSG-Bell Creek Complex and will be connected to
the 115 kV circuit P7G which is radially connected to the Porcupine TS 115 kV bus. The existing
complex is currently supplied by a 27.6 kV feeder from Hoyle TS connected to the 115 kV circuit
P7G. The connection applicant is planning to expand its operations beyond the capability of their
existing supply. Consequently, the connection applicant is seeking to become a transmission customer.
The proposed in-service date for the new station is May 2012.
This report provides a list of requirements for the connection applicant, to ensure that proposed
project, when connected, will not have a material adverse impact on the reliability of IESO-controlled
grid, and also points out significant Market Rules for connected wholesale customers.
SIA Findings
The findings of the assessment are summarized as follows:
(1) The proposed project is not expected to cause any thermal concerns for the transmission system.
(2) The pre-contingency and post-contingency system voltage levels and post-contingency voltage
changes in the area are expected to remain within the acceptable ranges following the
connection of the proposed project.
(3) The proposed project is not expected to materially impact the voltage stability in the
Northeastern system.
(4) Steady state voltage performance after motor starting is acceptable as per the Appendix 2 of
Transmission System Code.
IESO’s Requirements for Connection
Transmitter Requirements
•
The transmitter must submit any proposed protection relay modifications to the IESO as soon as
the protection assessment for the new facility is finished or at least six (6) months before any
actual modifications are to be implemented on the existing protection systems.
Connection Applicant Requirements
Specific Requirements:
The following specific requirements are applicable to the connection applicant for the incorporation of
the project. Specific requirements pertain to the level of reactive compensation needed, operation
restrictions, Special Protection Systems (SPS), upgrading of equipment and any project specific items
not covered in the general requirements:
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System Impact Assessment Report
Executive Summary
(1) The project will have to participate in the Northeast LGR scheme. Currently, under this scheme
the P7G line can be tripped for the D501P or P502X contingency or the loss of Porcupine 115
kV autotransformers. Hence, by configuration the project will participate in the Northeast LGR
scheme.
General Requirements:
The connection applicant shall satisfy all applicable requirements and standards specified in the
Market Rules, Market Manuals and the Transmission System Code. The following requirements
summarize some of the general requirements that are applicable to the proposed project, and presented
in detail in section 2 of this report.
(1) The connection applicant shall have the capability to maintain the power factor at the defined
meter point of the proposed project within the range of 0.9 lagging and 0.9 leading.
(2) The connection applicant shall ensure that the 115 kV equipment is capable of continuously
operating between 113 kV and 132 kV. Protective relaying must be set to ensure that
transmission equipment remains in-service for voltages between 94% of the minimum
continuous value and 105% of the maximum continuous value specified in Appendix 4.1of the
Market Rules.
(3) The connection applicant shall ensure that revenue metering installations comply with Chapter 6
of the Market Rules. For more details the connection applicant is encouraged to seek advice
from their Metering Service Provider (MSP) or from the IESO metering group.
(4) The connection applicant shall ensure that the new equipment at the facility is designed to
sustain the fault levels in the area. If any future system enhancement results in an increased fault
level higher than the equipment’s capability, the connection applicant is required to replace the
equipment at its own expense with higher rated equipment capable of sustaining the increased
fault level, up to maximum fault level specified in Appendix 2 of the Transmission System
Code.
Fault interrupting devices must be able to interrupt fault currents at the maximum continuous
voltage of 132 kV.
(5) Appendix 2 of the Transmission System Code states that the maximum rated interrupting time
for the 115 kV breakers must be ≤ 5 cycles. Thus, the connection applicant shall ensure that the
installed breakers meet the required interrupting time specified in the Transmission System
Code.
(6) The connection applicant shall ensure that the telemetry requirements are satisfied as per the
applicable Market Rules requirements. The determination of telemetry quantities and telemetry
testing will be conducted during the IESO Facility Registration/Market Entry process.
(7) The connection applicant shall ensure that the Under Frequency Load Shedding (UFLS) targets
specified in Section 10.4.6 of Chapter 5 of the Market Rules and Section 4.5 of Market Manual
7.4 are met after the proposed changes are implemented. The connection applicant is required to
submit during the IESO Market Entry process a revised schedule of feeder selections and their
related load amounts for each shedding stage that will ultimately satisfy the UFLS targets. If the
connection applicant is part of the UFLS Program Implementation Plan, they are required to
take into account the new configuration when implementing the plan.
(8) The connection applicant shall ensure that the connection equipment is designed to be fully
operational in all reasonably foreseeable ambient temperature conditions. The connection
equipment must also be designed so that the adverse effects of its failure on the IESO-controlled
grid are mitigated. This includes ensuring that all circuit breakers fail in the open position.
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Executive Summary
(9) The connection applicant shall ensure that faults within the facility do not trip the 115 kV circuit
P7G except for a failure of the project’s 115 kV main circuit breakers. If tripping of the P7G
occurs due to events within the proposed facility, the project may be required to disconnect from
the IESO-controlled grid until the problem is solved to the satisfaction of the IESO.
(10) Based on the SIA application, the connection applicant meets the restoration participant criteria.
Please refer to the Market Manual 7.8 to determine its applicability to the proposed facility.
Details regarding restoration participant requirements will be finalized at the Facility
Registration/Market Entry Stage.
(11) The project must be compliant with applicable reliability standards set by the North American
Electric Reliability Corporation (NERC) and the North East Power Coordinating Council
(NPCC) that are in effect in Ontario as mapped in the following link:
http://www.ieso.ca/imoweb/ircp/orcp.asp
(12) The connection applicant must complete the IESO Facility Registration/Market Entry process in
a timely manner before IESO final approval for connection is granted.
Models and data, including any controls that would be operational, must be provided to the
IESO at least seven months before energization to the IESO-controlled grid. This includes both
PSS/E and DSA software compatible mathematical models representing the new equipment for
further IESO, NPCC and NERC analytical studies.
The connection applicant must also provide evidence to the IESO confirming that the equipment
installed meets the Market Rules requirements and matches or exceeds the performance
predicted in this assessment. This evidence shall be either type tests done in a controlled
environment or commissioning tests done on-site. The evidence must be supplied to the IESO
within 30 days after completion of commissioning tests. If the submitted models and data differ
materially from the ones used in this assessment, then further analysis of the project will need to
be done by the IESO.
(13) The connection applicant shall ensure that the new protection systems at the project are designed
to satisfy all the requirements of the Transmission System Code and any additional requirements
identified by the transmitter.
As currently assessed by the IESO, the proposed facility is not part of the Bulk Power System
(BPS) and, therefore it is not designated as essential to the power system.
The connection applicant shall have adequate provision in the design of protections and controls
at the project to allow for future installation of Special Protection Scheme (SPS) equipment.
(14) Final connection of the project may also be subject to additional requirements specified in the
Customer Impact Assessment (CIA) performed by the applicable Transmitter (Hydro One). The
CIA will evaluate the impact of the project on the customers connected to the transmission
system. If necessary, any additional requirements resulting from the CIA will be included in the
final SIA report or in an Addendum to the final SIA report.
Notification of Conditional Approval
The addition of the project supplying up to 40 MW of load does not result in any significant adverse
impacts to the IESO-controlled grid, provided that the requirements listed in this report are met.
It is recommended that a Notification of Conditional Approval for Connection be issued to LSG Bell
Creek Complex subject to the requirements listed in this report being implemented.
– End of Section –
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System Impact Assessment Report
Project Description
1. Project Description
The connection applicant is proposing to develop a new load supply point for the LSG Bell Creek
Complex Expansion onto the 115 kV circuit P7G in Northeast, Ontario. The site is currently supplied
by a 27.6 kV feeder from Hoyle TS connected to the 115 kV circuit P7G. The existing complex
currently uses 6.3 MW which is close to the maximum capacity of feeder. The proposed new station
will be tapped directly to the P7G circuit via 0.25 km overhead line between Goldcentre and Pamour
junctions, roughly 10 km Northeast of Porcupine TS.
The project will incorporate 2 x 25/26.6 MVA, 115 kV/27.6 kV, Delta-Wye connected transformers,
designated as T1 and T2. The transformers will have their high voltage side connected through
motorized disconnect switches, rated at 145 kV maximum continuous voltages, 2000 A continuous
current, and 42 kA momentary short circuit capability and high voltage circuit breakers, rated at 1200
A continuous and 20 kA symmetrical short circuit capability. The low voltage side of the transformers
will be connected to one 27.6 kV switchgear via secondary breakers, 52-1 and 52-2, rated at maximum
continuous voltage of 15 kV and 2000 A continuous current. The bulk of the loads are two large
synchronous motors each rated 6235 Hp, 5.388 MVA at 0.9 power factor lagging. The motors are
supplied via the 27.6 kV switchgear that is connected through a 12/16 MVA, 27.6/6.6 kV, Delta-Wye
connected transformer and a 27.6 kV feeder, approximately 4.2 km in length.
The project will come in service in May 2012, with a load of 40 MW at 0.9 power factor (lagging).
Because at this load level the connection applicant would exceed the maximum capability of their
current supply, therefore, the connection applicant is seeking to become a transmission customer,
connecting directly to the IESO-controlled grid at the 115 kV level. The proposed connection
arrangement of the project is shown in figure 1.
115 kV P7G line
LSG-TAP
To 115 kV
Porcupine TS
M
To Kidd creek
Metsite
89-1
Bell Creek
115 kV BUS
LIGHTING ARRESTOR
M
89-3
M
T1
115 kV/27.6 kV
25 MVA ONAN
89-2
T2
115 kV/27.6 kV
25 MVA ONAN
52-2
52-1
27.6 kV O/H LINE EAST
4.2 km,
OVERHEADLINE
WEST 4.2 km
APPROX 15-20 MVA
FUTURE LOAD
MCC
(STATION
SERVICE)
SPARE
SPARE
27.6 kV O/H LINE
T3-SAG MILL
27.6kV/6.6kV,
12/16 MVA, Z=6%
27.6 kV/0.6 kV,
3/4MVA, Z=5%
TO EXISTING
MILL
600 V
SWITCHGEAR
SAG MILL
MOTOR 1
SAG MILL
MOTOR 2
Figure 1: LSG Bell Creek Complex Single Line Diagram
– End of Section –
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IESO’s General Requirements
2. IESO’s General Requirements
The connection applicant shall satisfy the applicable requirements and standards specified in the
Market Rules, Market Manuals and the Transmission System Code. The following sections highlight
some of the general requirements that are applicable to the project.
2.1 Voltage
Appendix 4.1 of the Market Rules states that under normal operating conditions, the voltages in the
115 kV system in northern Ontario are maintained within the range of 113 kV to 132 kV. Thus, the
IESO requires that the 115 kV equipment in northern Ontario must have a maximum continuous
voltage rating of at least 132 kV.
Protective relaying must be set to ensure that transmission equipment remains in-service for voltages
between 94% of the minimum continuous value and 105% of the maximum continuous value specified
in Appendix 4.1of the Market Rules.
2.2 Power Factor
Appendix 4.3 of the Market Rules requires the connected wholesale customers and distributors
connected to the IESO-controlled grid to have the capability to maintain a power factor within the
range of 0.9 lagging and 0.9 leading as measured at the defined meter point of the facility.
The connection applicant shall have the capability to maintain the power factor at the defined meter
point within the range of 0.9 lagging to 0.9 leading.
2.3 Protection Systems
The connection applicant shall ensure that the protection systems are designed to satisfy all the
requirements of the Transmission System Code as specified in Schedules E, F and G of Appendix 1
and any additional requirements identified by the transmitter. New protection systems must be
coordinated with the existing protection systems.
Facilities that are essential to the power system must be protected by two redundant protection systems
according to section 8.2.1a of the TSC. These redundant protections systems must satisfy all
requirements of the TSC, and in particular, they must not use common components, common battery
banks or common secondary CT or PT windings. As currently assessed by the IESO, this facility is not
currently part of the BPS, and therefore, is not considered essential to the power system. In the future,
as the electrical system evolves, this facility may become part of the BPS.
The connection applicant is required to have adequate provision in the design of protections and
controls at the facility to allow for future installation of Special Protection Scheme (SPS) equipment.
Should a future SPS be installed to improve the transfer capability in the area or to accommodate
transmission reinforcement projects, the facility will be required to participate in the SPS system and
to install the necessary protection and control facilities to affect the required actions.
The connection applicant is required to initiate an assessment of the protection systems proposed for
the new facility with the transmitter.
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System Impact Assessment Report
IESO’s General Requirements
The transmitter shall identify any protection relay modifications (e.g. equipment and settings) required
to incorporate the new facility into the integrated power system. To allow sufficient time to assess the
impact on power system reliability, the transmitter must submit any proposed protection relay
modifications to the IESO as soon as the protection assessment for the new facility is finished or at
least six (6) months before any actual modifications are to be implemented on the existing protection
systems.
The IESO will evaluate the impact on system reliability due to any protection relay modifications and
any modifications to functionality, timing or reach. The IESO will not assess aspects of protection
systems which are solely the accountability of the transmitter (e.g. coordination of protection relays).
2.4 Breaker Interrupting Time
Appendix 2 of the Transmission System Code states that the maximum rated interrupting time for the
115 kV breakers must be ≤ 5 cycles. Thus, the connection applicant shall ensure that the installed
breakers meet the required interrupting time specified in the Transmission System Code.
2.5 Fault Levels
The Transmission System Code requires the new equipment to be designed to sustain the fault levels
in the area where the equipment is installed. Thus, the connection applicant shall ensure that the new
equipment at the facility is designed to sustain the fault levels in the area. If any future system
enhancement results in an increased fault level higher than the equipment’s capability, the connection
applicant is required to replace the equipment at its own expense with higher rated equipment capable
of sustaining the increased fault level, up to maximum fault level specified in the Transmission System
Code. Appendix 2 of the Transmission System Code establishes the maximum fault levels for the
transmission system. For the 115 kV system, the maximum 3 phase and single line to ground
symmetrical fault levels currently prescribed by the Code are 50 kA.
Fault interrupting devices must be able to interrupt fault currents at the maximum continuous voltage
of 132 kV.
2.6 Under frequency Load Shedding (UFLS)
The connection applicant has a total peak load at all its stations that is equal to or greater than 25 MW
(40 MW), therefore, is required to participate in the UFLS according to Section 4.5 of the Market
Manual Part 7.4.
In all automatic UFLS areas, there must be at least 30% of area load connected to under-frequency
relays according to Section 10.4, Chapter 5 of the Market Rules. In order to ensure at least 30% of area
load shedding is achieved while taking into account UFLS relay and feeder outages as well as
generation units that trip prematurely for low frequencies, 35% of the load of those distributors and
connected wholesale customers with a peak load of 25 MW or greater must be connected to UFLS
relays.
Each connected wholesale customer shall select load for UFLS based on their load distribution at a
date and time specified by the IESO that approximates system peak.
For connected wholesale customers with a peak load of 25 MW or more and less than 50 MW, the
UFLS relay connected loads shall be set to achieve the amounts to be shed stated in the following
table:
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IESO’s General Requirements
UFLS
Stage
Frequency
Threshold (Hz)
Total Nominal
Operating Time (s)
Load Shed at stage
as % of MP Load
Cumulative Load
Shed at stage as %
of MP Load
1
59.5
0.3
≥ 35
≥ 35
Connected wholesale customers are allowed some time, as stated in the Ontario UFLS Program
Implementation Plan, to implement the required changes to meet the requirements in (d). Each
distributor and connected wholesale customer, in conjunction with the relevant transmitter, shall
submit to the IESO their proposed implementation plan for meeting their UFLS requirements within
the time set by the Ontario UFLS Program Implementation Plan.
Connected wholesale customers, in conjunction with the relevant transmitter shall also shed those
capacitor banks connected to the same station bus as the load to be shed by the UFLS facilities, at 59.5
Hz with a time delay of 3 seconds.
Inadvertent operation of a single under-frequency relay during the transient period following a System
Disturbance should not lead to further system instability. For this reason, the maximum amount of
load that can be connected to any single under-frequency relay is 150 MW.
2.7 Telemetry
If applicable according to Section 7.3 of Chapter 4 of the Market Rules, Lake Shore Gold-Bell Creek
Complex shall provide to the IESO the applicable telemetry data listed in Appendix 4.15 of the Market
Rules on a continual basis. The data shall be provided in accordance with the performance standards
set forth in Appendix 4.19, subject to Section 7.6A of Chapter 4 of the Market Rules. The data is to
consist of certain equipment status and operating quantities which will be identified during the IESO
Facility Registration/Market Entry Process.
To provide the required data, The connection applicant must install at this project monitoring
equipment that meets the requirements set forth in Appendix 2.2 of Chapter 2 of the Market rules. As
part of the IESO Facility Registration/Market Entry process, the connection applicant must also
complete end to end testing of all necessary telemetry points with the IESO to ensure that standards
are met and that sign conventions are understood. All found anomalies must be corrected before IESO
final approval to connect any phase of the project is granted.
2.8 Revenue Metering
The connection applicant must ensure that revenue metering installations must comply with Chapter 6
of the Market Rules. For more details the connection applicant is encouraged to seek advice from
their Metering Service Provider (MSP) or from the IESO metering group.
2.9 Connection Equipment Design
The connection applicant shall ensure that the connection equipment is designed to be fully
operational in all reasonably foreseeable ambient temperature conditions. The connection equipment
must also be designed so that the adverse effects of its failure on the IESO-controlled grid are
mitigated. This includes ensuring that all circuit breakers fail in the open position.
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IESO’s General Requirements
2.10 Restoration Participant Requirements
Based on the SIA application, the connection applicant meets the restoration participant criteria.
Please refer to the Market Manual 7.8 to determine its applicability to the proposed facility. Details
regarding restoration participant requirements will be finalized at the Facility Registration/Market
Entry Stage
2.11 Reliability Standards
Prior to connecting to the IESO controlled grid, the project must be compliant with the applicable
reliability standards established by the North American Electric Reliability Corporation (NERC) and
reliability criteria established by the Northeast Power Coordinating Council (NPCC) that are in effect
in Ontario. A mapping of applicable standards, based on the proponent’s/connection applicant’s
market role/OEB license can be found here: http://www.ieso.ca/imoweb/ircp/orcp.asp
This mapping is updated periodically after new or revised standards become effective in Ontario.
The current versions of these NERC standards and NPCC criteria can be found at the following
websites:
http://www.nerc.com/page.php?cid=2|20
http://www.npcc.org/documents/regStandards/Directories.aspx
The IESO monitors and assesses market participant compliance with a selection of applicable
reliability standards each year as part of the Ontario Reliability Compliance Program. To find out
more about this program, write to orcp@ieso.ca or visit the following webpage:
http://www.ieso.ca/imoweb/ircp/orcp.asp
Also, to obtain a better understanding of the applicable reliability compliance obligations and engage
in the standards development process, we recommend that the proponent/ connection applicant join the
IESO’s Reliability Standards Standing Committee (RSSC) or at least subscribe to their mailing list by
contacting rssc@ieso.ca. The RSSC webpage is located at:
http://www.ieso.ca/imoweb/consult/consult_rssc.asp
2.12 Facility Registration/Market Entry
The connection applicant must complete the IESO Facility Registration/Market Entry process in a
timely manner before IESO final approval for connection is granted.
Models and data, including any controls that would be operational, must be provided to the IESO.
This includes both PSS/E and DSA software compatible mathematical models representing the new
equipment for further IESO, NPCC and NERC analytical studies. The connection applicant may need
to contact the software manufacturers directly, in order to have the models included in their packages.
This information should be submitted at least seven months before energization to the IESO-controlled
grid, to allow the IESO to incorporate this project into IESO work systems and to perform any
additional reliability studies.
As part of the IESO Facility Registration/Market Entry process, The connection applicant must
provide evidence to the IESO confirming that the equipment installed meets the Market Rules
requirements and matches or exceeds the performance predicted in this assessment. This evidence
shall be either type tests done in a controlled environment or commissioning tests done on-site. In
either case, the testing must be done not only in accordance with widely recognized standards, but also
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IESO’s General Requirements
to the satisfaction of the IESO. Until this evidence is provided to and found acceptable by the IESO,
the Facility Registration/Market Entry process will not be considered complete and the connection
applicant must accept any restrictions the IESO may impose upon this project’s participation in the
IESO-administered markets or connection to the IESO-controlled grid. The evidence must be supplied
to the IESO within 30 days after completion of commissioning tests. Failure to provide evidence may
result in disconnection from the IESO-controlled grid.
If the submitted models and data differ materially from the ones used in this assessment, then further
analysis of the project will need to be done by the IESO.
– End of Section –
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Data Verification
3. Data Verification
This section verifies the specifications for the new equipment proposed by the connection applicant to
be installed at LSG Bell Creek Complex substation.
Overhead Circuit Section
Quantity
1
LSG-TAP (0.25km)
Rated voltage
115 kV
Positive sequence impedance
R= 0.0019 pu, X= 0.0026 pu, B= 0.0005 pu
Zero sequence impedance
R0 = 0.0086 pu, X0 = 0.007 pu, B0 = 0.001 pu
Main Buses
Quantity
1
Rated voltage
115 kV
Summer continuous ratings
400 A
Winter continuous ratings
400 A
Disconnect Switches
Maximum continuous rated voltage
145 kV
Continuous current rating
2000 A
Rated symmetrical short circuit capability
42 kA
HV Circuit Breaker
Maximum continuous rated voltage
145 kV
Rated continuous current
1200 A
Interrupting time
1
-
Rated symmetrical short circuit capability
20 kA
Normal operation
Closed
Step-down Transformer
Quantity
2
Configuration
3 phase, 2 winding
Thermal ratings
25 MVA (ONAN)
Winding rated voltage
115 kV/27.6 kV (delta/wye)
1
The interrupting time of the HV Circuit Breaker was not provided at the time of the assessment. Please refer to section 2.4 of
this report for the breaker interrupting time requirements.
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Data Verification
Under-load taps
132 kV-113 kV in 20 steps
Positive sequence Impedance
R= 10%, X= 10 % on 25 MVA base
Motors
Type
Synchronous (6235 HP)
Quantity
2
Rated capability
5.388 MVA
Rated power factor
0.9 (lagging)
Starting method
Full Voltage
Starts per week
once
Type
Synchronous (1500Hp Ball Mill)
Quantity
2
Rated capability
1.12 MVA
Rated power factor
0.98 (lagging)
Starting method
Soft Starting
Starts per week
once
The symmetrical rated short circuit capability of the 115 kV breaker and disconnect switches are 20
kA and 42 kA respectively. The short circuit analysis shown in Section 6 of this report indicates that
the 115 kV breaker rating of 20 kA is sufficient to withstand fault levels at LSG Bell Creek Complex.
The connection applicant should be aware that if any future system enhancements results in an
increased fault level higher than the equipment’s capability, the connection applicant would be
required to replace this breaker and disconnect switches at its own expense up to maximum fault level
specified in the Transmission System Code, Appendix 2. For the 115 kV system, the maximum 3
phase and single line to ground symmetrical fault levels currently prescribed by the Code are 50 kA.
– End of Section –
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Review of Existing System
4. Review of Existing System
4.1 Existing System
Figure 2 provides an overview of the transmission system in the vicinity of the project. The project
will be supplied directly from the radial 115 kV single circuit line, P7G, which is part of the Porcupine
115 kV system. Also part of the 115 kV system are two circuits, P13T and P15T from Porcupine TS to
Timmins TS. The 115 kV Porcupine TS is connected to the 500 kV Porcupine TS via two
autotransformers T3 and T4. The 500 kV Porcupine TS is connected to the Hanmer TS and Pinard TS
via P502X and D501P circuits respectively. The Porcupine 500 kV system is also connected to 230 kV
system through two autotransformers, T7 and T8.
During outages on the 230 kV circuit, P91G, the Falconbridge Kidd Creek Metsite load is moved over
onto the 115 kV circuit, P7G. The generation facilities in the area include the Abitibi Canyon,
Cochrane, Tunis, and Long Sault Rapid. These generation facilities participate in the Northeast
Load/Generation Rejection (LGR) Scheme and can be armed for rejection for any of the D501P or
P502X contingency or the loss of Porcupine auto transformer T3 or T4. They can also be armed for
the P91G, H6T, or H7T contingencies to limit the post contingency flows over H6T and H7T circuits.
For the D501P or P502X contingency or the loss of Porcupine 115 kV autotransformers, the load
rejection on Timmins TS and the 115 kV lines P7G, P15T and T61S can be armed. As the project is
connecting to P7G line which can be tripped for the aforementioned contingencies, therefore, by
configuration the project will be participating in the Northeast LGR scheme.
The Flow South (FS) interface is currently limited to 2100 MW with all elements in service precontingency. Historical data analysis reveals that the flow towards south occurs during the day while
the flow reverses over night. Higher flow south typically occurs in summer when the load in Northeast
is below winter levels.
A5H to
Ansonville
115 kV
To 500 kV
Pinard TS
To Abitibi Canyon TS
230 kV
Kinross
C2H
500 kV
Tunis NUG
C3H
Hoyle
Cochrane NUG
Goldcentre
LSR NUG
H9K
To Smooth Rock Falls TS
La Forest
Road
A4H to
Ansonville
P13T
T3
Timmins TS
P15T
D501P
N.O.
Falconbridge
Kidd Creek
Minesite
H7T
P7G
10 km
H6T
T61S
T4
Porcupine TS
P502X
Dome Goldcentre
Mine
CTS
T7
Pamour Hoyle
LSG Bell
Creek
Complex
To 500 kV
Hanmer TS
Kinross
Falconbridge
Kidd Creek
Metsite
P91G
Weston
Lake
Timmins
West
Mine CTS
Shining
Tree
To 220 kV
Ansonville TS
T8
Figure 2: Transmission System in the vicinity of the project
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4.2 Historical data
Historical data, consisting of hourly average samples from May 2009 - May 2011, were obtained from
IESO real-time telemetry for the following quantities:
-
Voltage (kV) at Porcupine 500kV and 115 kV buses
-
Active (MW) power flow on D501P, P502X, H6T, H7T, Porcupine 500:115 kV transformers
T3 and T4
-
Total 220 kV generation (MW) of Abitibi Canyon, Otter Rapids, Harmon, Kipling, Little
Long plants
-
Total 115 kV generation (MW) of TCPL Tunis, NP Cochrane, Long Sault plants
Relevant Graphs for these quantities are presented below. Note that for active power flows, positive
values represent flows out of the station and negative values represent flows into the station. Figure 4
and 5 suggests that high active power flow through the 500 kV lines D501P and P502X occurs in
south direction. Also the flow south occurs for more than 70 % of the time.
Porcupine 115 kV bus voltage
Voltage (kV)
138.
133.
128.
123.
118.
113.
0%
20%
40%
60%
80%
100%
Percent of time
Figure 3: Porcupine 115 kV bus voltage duration curve
D501 500 kV line flow
Power Flow (MW)
400.
200.
0.
-200.
0%
20%
40%
60%
80%
100%
-400.
-600.
-800.
-1,000.
Percent of time
Figure 4: D501 500 kV line flow measured at Porcupine TS.
Note: Positive flow is out from the station
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P502X 500 kV line flow
Power Flow (MW)
1,000.
800.
600.
400.
200.
0.
-200. 0%
20%
40%
60%
80%
100%
-400.
-600.
Percent of time
Figure 5: P502X 500 kV line flow measured at Porcupine TS
Note: Positive flow is out from the station
Table 3, 4 and 5 shows the historical voltages at the main stations, the flows along the lines, and the
maximum output of the generators in the Northeast in the vicinity of the proposed project.
Table 1: Average voltages at main stations
Bus
Range
Average Voltage
Porcupine TS (500kV)
510-550 kV
536 kV
Porcupine TS (115kV)
125-132 kV
128 kV
Table 2: Flows on circuits
Quantity
Maximum
Active Flow on D501P into Porcupine
835 MW
Active Flow on P502X out of Porcupine
1018 MW
Active Flow on H6T into Timmins TS
97 MW
Active Flow on H7T into Timmins TS
89 MW
Active Flow into Porcupine T3 and T4
150 MW
Table 3: Generation output
Voltage
Generation plants
Max. Generation
230 kV
Abitibi Canyon (G1, G4, G5), Otter
Rapids, Harmon, Kipling, Little Long
940 MW
115 kV
Abitibi Canyon (G2, G3)
135 MW
115 kV
TCPL Tunis, NP Cochrane, Long
Sault
109 MW
–End of Section –
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System Impact Assessment Studies
5. System Impact Assessment Studies
This section presents the study carried out to investigate the impact of the project on the reliability of
IESO-controlled grid.
5.1 Study Criteria
The SIA study was performed to assess the project’s compliance with the following sections2 of the
Ontario Resource and Transmission Assessment Criteria (ORTAC):
•
Section 2.4 – Load Forecasts and Load Modelling:
The load levels used in the study shall be based on the latest forecast consistent with the IESO's
and the OPA's latest long-term forecast. Load forecast uncertainty should be taken into account
by investigating the sensitivity of the need date to various items (e.g. higher and lower loads).
If a connection assessment applicant provides a detailed local forecast, that forecast should be
used.
For assessment purposes the power factor is assumed to be 0.90 at the defined meter point.
Studies should be done with a load model representative of the actual load. For power flow
planning studies assessing the voltage stability of the bulk system, loads normally should be
modelled as constant megavolt-amperes (MVA). In assessing voltage change limits and
transient performance, a voltage dependent load model should be used. If specific information
is not available, the load model in Ontario should be as indicated in the following table:
Table 4: Static Load Models for Simulations
Active Power
•
Reactive Power
Constant Current
Constant
Impedance
Constant
Current
Constant
Impedance
(%)
(%)
(%)
(%)
50
50
0
100
Section 2.5 – Power Transfer Capability:
A power transfer capability analysis should be performed throughout the study period taking
into account the effects of planned facilities, the growth in loads, and the effects (if any), of
various system generation patterns. The transfer limits should be determined for one or both
directions of flow (as necessary).
With all transmission facilities in service, the power transfer capability is determined for the
worst applicable contingency. Also, it will generally be necessary to determine the effects of
seasonal variations (e.g., summer and winter line ratings) on the limits.
2
Only significant paragraphs of the ORTAC sections were copied/summarized in this report; please refer to the original
document for the complete text:
http://www.ieso.ca/imoweb/pubs/marketAdmin/IMO_REQ_0041_TransmissionAssessmentCriteria.pdf. In the event of any
inconsistency between this report and the ORTAC, the ORTAC shall prevail to the extent of the inconsistency.
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System Impact Assessment Studies
Section 2.6 – Local Area Requirements:
With all transmission facilities in service (normal conditions), the schedule for generation in
the receiving area should be based on the historically typical conditions. That is, for precontingency conditions, nuclear and run of river hydro-electric generation should be assumed
at a level that is available 98% of the time. For example, on-peak conditions should be assessed
with peaking hydroelectric generation plants, fossil plants and wind farms running at maximum
output. Where reliability depends on local generation, sensitivity studies should be done to
assess the impact of outages of local generation.
•
Section 2.7 – Contingency-Based Assessment
The IESO-controlled grid must be planned with sufficient capability to withstand the loss of
specified, representative and reasonably foreseeable contingencies at projected customer
demand and anticipated transfer levels. Application of these contingencies should not result in
any criteria violations, or the loss of a major portion of the system, or unintentional separation
of a major portion of the system. The IESO-controlled grid shall be designed with sufficient
capability to keep voltages, line and equipment loading within applicable limits for these
contingencies.
•
Section 2.8 – Study conditions:
The system load and generation conditions under which the contingencies are assumed to occur
are chosen on a deterministic basis to represent the reasonable worst case scenario.
•
Section 4.2 – Pre-contingency voltage limits:
Under pre-contingency conditions with all facilities in service, or with a critical element(s) out
of service after permissible control actions and with loads modeled as constant MVA, the IESO
controlled grid is to be capable of achieving acceptable system voltages. For northern Ontario,
acceptable system voltages on nominal 115 kV buses are between 113 kV and 132 kV.
•
Section 4.3 – Voltage change limits:
With all planned facilities in service pre-contingency, system voltage changes in the period
immediately following a contingency are to be limited, for nominal 115 kV buses to 10%
before and after tap changer action and between 108 kV and 127 kV.
After the system is re-dispatched and generation and power flows are adjusted the system must
return to within the maximum and minimum continuous voltages identified in section 4.2.
Before tap-changer action (immediate post-contingency period) a constant MVA load model
can be used. If the voltage change exceeds the limits identified above, a voltage dependent load
model should be used (e.g. P α V1.5, and Q α V2). After tap-charger action a constant power
load model should be assumed (e.g. the load will return to its pre-contingency level).
The percentage change in voltage is calculated as follows:
%Vch =
Vpost-contingency –Vpre-contingency x 100
Vpre-contingency
Section 4.5.1 – Power – Voltage (P-V) Curves:
The critical point of the curve, or voltage instability point, is the point where the slope of the PV curve is vertical. The maximum acceptable pre-contingency power transfer must be the
lesser of:
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•
a pre-contingency power transfer (point A) that is 10% lower than the voltage
instability point of the pre-contingency P-V curve, and
•
a pre-contingency transfer that results in a post-contingency power flow (point B)
that is 5% lower than the voltage instability point of the post-contingency curve.
The P-V curve is dependent on the power factor. Care must be taken that the worst case P-V
curve is used to identify the stability limit.
•
Section 4.7.2 – Loading Criteria:
All line and equipment loads shall be within their continuous ratings with all elements in
service and within their long-term emergency ratings with any one element out of service.
Immediately following contingencies, lines may be loaded up to their short-term emergency
ratings where control actions such as re-dispatch, switching, etc. are available to reduce the
loading to the long-term emergency ratings.
•
Section 7.1 – Load Security Criteria:
The transmission system must be planned to satisfy demand levels up to the extreme weather,
median-economic forecast for an extended period with any one transmission element out of
service. The transmission system must exhibit acceptable performance, as described below,
following the design criteria contingencies defined in sections 2.7.1 and 2.7.2. For the purposes
of this section, an element is comprised of a single zone of protection.
With all transmission facilities in service, equipment loading must be within continuous
ratings, voltages must be within normal ranges and transfers must be within applicable normal
condition stability limits. This must be satisfied coincident with an outage to the largest local
generation unit.
With any one element out of service3, equipment loading must be within applicable long-term
emergency ratings, voltages must be within applicable emergency ranges, and transfers must be
within applicable normal condition stability limits. Planned load curtailment or load rejection,
excluding voluntary demand management, is permissible only to account for local generation
outages. Not more than 150MW of load may be interrupted by configuration and by planned
load curtailment or load rejection, excluding voluntary demand management. The 150MW
load interruption limit reflects past planning practices in Ontario.
With any two elements out of service4, voltages must be within applicable emergency ranges,
equipment loading must be within applicable short-term emergency ratings and transfers must
be within applicable emergency condition stability limits. Equipment loading must be reduced
to the applicable long-term emergency ratings in the time afforded by the short-time ratings.
Planned load curtailment or load rejection exceeding 150MW is permissible only to account
for local generation outages. Not more than 600MW of load may be interrupted by
configuration and by planned load curtailment or load rejection, excluding voluntary demand
management. The 600MW load interruption limit reflects the established practice of
incorporating up to three typical modern day distribution stations on a double-circuit line in
Ontario.
The percentage loading of the equipment is calculated as follows:
%L=
Equipment Loading × 100
Equipment Rating
The loadings and ratings are in Amperes for lines and in MVA for transformers.
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System Impact Assessment Studies
Appendix 4.2 TSC – Voltage Flicker :
Voltage flicker due to motor starting shall be limited as tabulated.
Magnitude (%)
Limit
0.5
3 per second
1.0
20 per minute
2.0
45 per hour
3.0
4 per day
A higher flicker may be acceptable for infrequent starts
For motor starting, the aforementioned criteria is applied to ensure that the voltage flicker due
motor starting at the LSG Bell Creek Complex is within the limits specified above, and shall
not exceed a maximum of 4%.
5.2 Study Assumptions
The following study assumptions were derived as per the ORTAC requirements listed in section 4.2 of
this report and are intended to simulate operations under a reasonable worst case scenario.
•
The new station would be supplied from 115 kV P7G line approximately 10 km north-east of
Porcupine TS;
•
The power factor for LSG Bell Creek Complex was assumed to be 0.9 lagging at the low
voltage side of the transformer station;
•
A 0.90 lagging power factor, as required under section 2.4 of the ORTAC, was assumed for the
loads at all stations in the area encompassed from Porcupine TS to Hunta & Ansonville TS.
•
Generation at Abitibi Canyon, Otter Rapids, Harmon, Kipling, Little Long were set to
maximum output for high active power flows south on circuit D501P;
•
The Porcupine SVC was assumed in service;
•
The Falconbridge Kidd Creek Metsite load was assumed to be connected to the P7G;
•
Voltages at the buses and flows along the lines were adjusted to historical levels;
•
As required by section 2.4 of the ORTAC a constant megavolt-ampere (MVA) load model was
used to represent Ontario loads. For cases where a voltage dependent model was required,
loads were modeled as 50% constant current and 50% constant impedance for the active power
and 100% constant impedance for the reactive power.
5.2.1
Existing/Committed Facilities
The following facilities were kept in service during this study.
Table 5: Existing/Committed facilities in the vicinity of the project
Facility Type
CAA ID
Porcupine Capacitors
Mattagami Lake Dam
Detour Lake
Project
Transmission
Generation
Load
2006-223
2007-266
2009-359
Porcupine SVC
Kirkland Lake SVC
Transmission
Transmission
2006-223
2006-223
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5.2.2
System Impact Assessment Studies
Hanmer Capacitor
Transmission
2008-352
Pinard Capacitors
Young Davidson
New Post Creek
Transmission
Load
Generation
2008-352
2008-312
2007-294
Load Forecast
The load forecast is calculated at 1% growth per year and is based on the coincident peak load
recorded at each station plus a reasonable margin to account for growth, measurement, and simulation
inaccuracies. A 0.90 lagging power factor, as required under section 2.4 of the ORTAC, was assumed
for the loads at all stations in the area.
Table 6: Loads in Porcupine area.
Station
Peak Load (MW)
Station
Peak Load
(MW)
Falconbridge Kidd Creek
Metsite
18.67
Falconbridge Kidd Creek
Minesite
34.03
Hoyle DS
13.79
La Forest Road
13.84
Kinross
9.81
Cochrane MTS
11.75
Dome Mine CTS
19.16
Cochrane West
3.73
Weston Lake
3.80
Shining Tree
3.61
Timmins West Mine CTS
7.14
Timmins TS
69.47
5.2.3
Line ratings
The circuit ratings used in the thermal assessment were provided by Hydro One. The MVA values are
calculated assuming 118.05 kV for the 115 kV circuits and 220 kV for the 230 kV circuits, as required
by the current system model. These are summarized in the following table below:
Table 7: Line Ratings
Thermal Rating at 30°C ambient temperature
& 4km/hr wind
Circuit
Continuous
LTE
Amperes
MVA
Amperes
MVA
P7G
620
126
790
161
P13T
890
182
1060
217
P15T
890
182
1140
233
H6T
380
78
380
78
H7T
380
78
380
78
D501P
1790
366
2210
452
P502X
2210
452
2210
452
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5.3 Contingency Based Assessment
5.3.1
Load Flow Scenario
The summer 2010 base case was used as the starting point for assessing the impact of the project on
the reliability of the IESO-controlled grid. Northeast load is generally a winter peak load. Also the
project is coming in-service in January 2012, so the system model was stressed to reflect the winter
2012 forecasted system including:
-
Ontario and Northeast zone demands at 23364 MW and 1893.2 MW, respectively.
-
LSG Bell Creek Complex load was modeled as 41.3 MW at 0.9 power factor (lagging).
-
Timmins, Dome mine, Hoyle, Kidd metsite and other neighbouring loads were scaled to
reflect the peak load forecast of 2012.
-
After dispatching the generators and scheduling the loads to the expected levels, Flow South
resulted at 1352.2 MW.
-
Abitibi Canyon unit G2 and G3 along with other generation units connected to Hunta TS were
considered as armed for P91G, H6T, and H7T contingencies as per the Northeast LGR
scheme. For the aforementioned contingencies, a total of 190 MW of Generation Rejection
(GR) was considered.
The voltages at the main buses around Porcupine TS with all elements in service are displayed in
Table 7.
Table 8: Voltage at main buses near LSG Bell Creek complex substation
Bus
5.3.2
Voltage (kV)
PORCUPINE TS 115 kV
123.8
KIDD_METSITE
121.6
115 kV
TIMMINS K1H6 115 kV
122.9
TIMMINS K23
123.2
115 kV
HUNTA SS
115 kV
127
LAFOREST
115 kV
122.9
ANSONVILLE 230 kV
236.5
PORCUPINE TS 230 kV
245.0
PORCUPINE TS 500 kV
542.8
Local Area Contingencies
For local areas, the IESO-controlled grid must exhibit acceptable performance following:
a. The loss of one element without a fault, and
b. A phase-to-phase-to-ground fault on any generator, transmission circuit, transformer or bus
section with normal fault clearing.
Typically, only single-element contingencies are evaluated. The IESO defines a single-element as a
single zone of protection.
The contingencies considered for this study were:
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1.
2.
3.
4.
5.
6.
7.
8.
System Impact Assessment Studies
Loss of Porcupine SVC.
Loss of 115 kV P13T circuit.
Loss of 115 kV P15T circuit.
Loss of 115 kV H6T circuit.
Loss of 115 kV H7T circuit.
Loss of 230 kV P91G circuit.
Loss of Porcupine Auto Transformer T3
Loss of Porcupine Auto Transformer T4
5.3.3
Equipment Loadings
Thermal study examined the effect of the project on the thermal loading of the transmission equipment
in its vicinity. Table A1 in Appendix A displays the results of the simulations for the contingencies
listed in section 5.2 of this report.
The results show that with the project connection, the flow on P7G and remaining circuits in the area
are expected to be within their continuous ratings with all elements in service. The sensitivity analysis
shows that the project would increase the thermal loading of the lines H6T and H7T by approximately
3% whilst the thermal loadings on the lines P13T and P15T would increase by 1.2 % and 1 %
respectively, with all elements in service. The highest loaded element was identified as being the
section of H6T line between Laforest and Timmins TS, at 94.1% of its continuous rating. The second
highest loaded element was identified to be the section of H7T line between Hunta TS and Warkus
junction, at 92.7 % of continuous line rating.
With one transmission element out of service, the loadings of the circuit P7G and remaining circuits in
the area are expected to be within their LTE ratings following the connection of the project. The
highest loaded element was identified as being the section of H6T line between Laforest and Timmins
TS, at 97.1%of LTE rating, following the loss of Porcupine T3 transformer with 190 MW of GR. A
second highest flow, 96.7 % of the LTE, is through the section connecting Warkus to Timmins along
the H7T circuit following the loss of P13T circuit. The second highest loaded element was identified
to be the section of H7T line between Warkus Junction and Timmins TS, at 92.7 % of continuous line
rating, following the loss of P13T circuit with 190 MW of GR.
As the peak P7G load is not expected to exceed 105 MW following the project’s connection, so less
than 150 MW of load would be interrupted for the loss of P7G circuit which satisfies the IESO load
security criteria.
5.3.4
Voltage Assessment
The results presented in Appendix B show the voltage levels with all elements in service, precontingency and percentage changes in voltages at the buses in the vicinity of project following the
contingencies listed in section 5.2 of this report.
With all elements in service pre-contingency, all voltages at the monitored buses are within the
acceptable range for both pre and post-contingency conditions.
The highest voltage changes recorded at the Bell Creek and Porcupine 115 kV bus were -5.7 % and 5.5 % (voltage decline) respectively, following the loss of H7T before tap action. A -7.2% voltage
change was observed at the Timins_K23 115 kV bus due to the loss of P15T before tap action.
After tap action, voltage change was reduced to 0.1% at the aforementioned buses. A post-ULTC
voltage decline of -8.9% was also recorded at the Timins_K23 bus for the loss of P15T line.
The voltage analysis did not identify any criteria violation as a result of connecting the project.
CAA ID 2011-425
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System Impact Assessment Report
5.3.5
System Impact Assessment Studies
Motor Start Study
The largest motor at the facility is the 5.388MVA synchronous motor which will start once per week.
The rest of load in the facility also includes other motors with lower starting currents.
To simulate the effect of the largest motor start, the station load less this largest motor was simulated
as voltage dependent load. The system voltages were monitored before and immediately after the
connection of an additional load equivalent to the motor start-up MVA. The results presented in
Appendix D show that the largest voltage decline at the LSG Bell Creek Complex 115 kV bus after
starting this motor is 2.36% which is within the permissible limits.
Motor Start Study shows that the starting of the largest synchronous motor of 5.388 MVA at the
project meets the TSC criteria. The connection applicant shall notify the IESO of any reactive devices
or motors larger in size or with higher starting times than those assessed in this study that are to be
installed at Bell Creek Complex.
5.3.6
Steady State Voltage Stability
The pre-contingency and post-contingency PV curves were derived for the high voltage buses in the
vicinity of the project.
Note that the transfer levels presented in this section are only theoretical, and were derived
ignoring thermal limitations of the equipment, with the sole purpose of assessing the steady state
voltage stability. Thermal ratings (presented in section 5.2.3 of this report) would limit the
maximum transfers to significantly lower levels.
The results of the pre-contingency and post-contingency voltage stability are presented in figure 6-7
and in Appendix D. The pre-contingency voltage instability point at 115 kV Bell Creek bus was
identified at 80 MW of load in addition to the proposed 40 MW of LSG Bell Creek Complex load;
hence, the IESO voltage stability criteria are met with the proposed load at LSG Bell Creek Complex.
The post-contingency voltage instability point at 115 kV Bell Creek bus for the loss of SVC at
Porcupine TS was identified at 70 MW of load in addition to the proposed 40 MW of LSG Bell Creek
Complex load; hence, the IESO voltage stability criteria are met with the proposed load at LSG Bell
Creek Complex.
Figure 6 and 7 shows the pre and post-contingency PV curves derived under this scenario. The x-axis
represents the MW load and y-axis represents the per unit voltage at the Bell Creek 115 kV bus.
1.15
Bus: 152899 [BELL CREEK 118.05]
1.10
1.05
1.00
BA SE CASE
SV C
P13T
P15T
H6T
H7T
P91G
T3
0.95
0.90
0.85
0.80
0
10
20
30
40
50
60
70
80
90
100
Figure 6: PV Curve-pre and post contingency voltages at Bell Creek 115 kV bus
Note: BASE CASE corresponds to all elements in service (pre-contingency case)
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System Impact Assessment Report
1.15
System Impact Assessment Studies
Bus: 152316 [PORCUPINE_TS118.05]
1.10
1.05
1.00
BA SE CASE
SV C
P13T
P15T
H6T
H7T
P91G
T3
0.95
0.90
0.85
0.80
0
10
20
30
40
50
60
70
80
90
100
Figure 7: PV Curve- pre and post contingency voltages at Porcupine 115 kV bus
Note: BASE CASE corresponds to all elements in service (pre-contingency case)
The Voltage Stability Analysis shows that the connection of the project does not have unacceptable
impact on the reliability of IESO controlled grid.
– End of Section –
CAA ID 2011-425
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System Impact Assessment Report
Fault Levels
6. Fault Levels
The purpose of the fault level assessment is to evaluate the maximum short circuit current contribution
of the project to the IESO-controlled grid.
The following table summarizes the symmetric and asymmetrical fault levels near project and
corresponding breaker ratings.
Table 9: Fault Level Assessments
New project in service
Bus
Total Fault Current
Symmetrical (kA)
Breaker Ratings
Total Fault Current
Asymmetrical (kA)
Symmetrical
(kA)
Asymmetrical
(kA)
3-ph
fault
L-G
3-ph
fault
L-G
BELL CREEK 118.05
6.559
5.81
6.897
5.939
20
-
PORCUPINE 118.05
11.133
13.942
13.217
17.53
40
46.5
TIMMINS K1 118.05
9.201
9.077
10.231
9.909
40
40.2
TIMMINS K23 118.05
9.364
9.293
10.434
10.19
40
40.2
HUNTA 118.05
9.385
5.847
9.778
6.168
40
47.9
PORCUPINE 220.00
7.223
8.983
9.449
12.356
40
42.1
PORCUPINE 500.00
6.848
7.004
8.266
9.158
63
79.4
ANSONVILE 220.00
5.496
5.837
6.888
7.601
40
42.1
ANSONVILE 118.05
8.54
9.021
9.594
10.528
40
40.2
ABITIBI CANYON 118.05
5.664
5.81
6.522
7.047
9.8
11.4
HANMER 500.00
12.974
12.502
14.59
15.237
40
43.7
HANMER 220.00
19.384
23.642
22.548
29.166
39.7
42.1
PINARD
13.026
16.439
16.631
22.103
50
53.9
220.00
The results show that following the connection of the project, the fault levels in the area are not
expected to exceed the interrupting capabilities of the existing breakers on the IESO-controlled grid.
– End of Section –
CAA ID 2011-425
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October 25, 2011
System Impact Assessment Report
References
7. References
[1] Ontario Resource and Transmisssion Assessment Criteria (ORTAC), available online:
http://www.ieso.ca/imoweb/pubs/marketAdmin/IMO_REQ_0041_TransmissionAssessmentCriter
ia.pdf
CAA ID 2011-425
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October 25, 2011
System Impact Assessment Report
Appendix A: Equipment Loading Results
Appendix A: Equipment Loading Results
Table A 1: Thermal Loading Assessment-with all elements in service Results
without the
project
CIRCUIT
FROM
with the
project
Loading
(%)
Loading
(%)
Cont
Rating
LTE
Rating
STE
Rating
TO
(A)
(A)
(A)
Loading
(A)
Cont
Loading
(A)
Cont
P7G
Porcupine TS 118.05
Dome_Mine_J 118.05
850
1100
1410
356.9
42.0%
583.5
68.6%
P7G
Dome_Mine_J 118.05
GoldCentre 118.05
620
790
960
252.7
40.8%
478.3
77.1%
P7G
GoldCentre 118.05
Bell Creek 118.05
620
790
960
253.0
40.8%
478.6
77.2%
P7G
Bell Creek 118.05
Pamour_J 118.05
620
790
960
254.2
41.0%
257.9
41.6%
P7G
Pamour_J 118.05
Hoyle_J 118.05
620
790
960
254.4
41.0%
258.1
41.6%
P7G
Hoyle_J 118.05
Kinross_J 118.05
620
790
960
178.5
28.8%
180.7
29.1%
P7G
Kinross_J 118.05
Ecstall_J 118.05
620
790
960
126.5
20.4%
127.7
20.6%
P7G
Ecstall_J 118.05
KD_CRK 118.05
1170
1430
1600
126.6
10.8%
127.8
10.9%
P7G
KD_CRK 118.05
KIDD_Metsite 118.05
1170
1430
1600
126.7
10.8%
127.8
10.9%
P13T
Porcupine TS 118.05
Timmins_K1 118.05
890
1060
1150
318.8
35.8%
326.5
36.7%
P15T
Porcupine TS 118.05
Timmins_K23 118.05
890
1140
1250
199.8
22.5%
204.0
22.9%
H6T
Hunta_SS 118.05
Tisdale_J 118.05
500
530
530
399.8
80.0%
411.3
82.3%
H6T
Tisdale_J 118.05
Laforest_RDJ 118.05
500
530
530
397.0
79.4%
408.6
81.7%
H6T
Laforest_RDJ 118.05
Timmins_K1 118.05
380
380
380
346.7
91.2%
357.7
94.1%
H7T
Hunta_SS 118.05
Warkus_J 118.05
500
530
530
452.1
90.4%
463.9
92.8%
H7T
Warkus_J 118.05
Timmins_K23 118.05
380
380
380
312.9
82.3%
323.4
85.1%
P91G
Ansonville 220.00
Anson_J91 220.00
1120
1440
1650
512.8
45.8%
509.6
45.5%
P91G
Anson_J91 220.00
KD_CRK_JP91 220.00
1120
1440
1650
513.1
45.8%
509.9
45.5%
P91G
KD_CRK_JP91 220.00
ERG_RES_JP91 220.00
1120
1440
1650
516.1
46.1%
512.9
45.8%
P91G
ERG_RES_JP91 220.00
Porcupine TS 220.00
1120
1440
1650
525.8
46.9%
522.7
46.7%
CAA ID 2011-425
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October 25, 2011
System Impact Assessment Report
Appendix A: Equipment Loading Results
Table A 2: Thermal Loading Assessment-Following the loss of Porcupine SVC
without the
project
CIRCUIT
FROM
with the
project
Loading
(%)
Loading
(%)
Cont
Rating
LTE
Rating
STE
Rating
(A)
(A)
(A)
Loading
(A)
LTE
Loading
(A)
LTE
TO
P7G
Porcupine TS 118.05
Dome_Mine_J 118.05
850
1100
1410
357.4
32.5%
582.7
53.0%
P7G
Dome_Mine_J 118.05
GoldCentre 118.05
620
790
960
253.0
32.0%
477.7
60.5%
P7G
GoldCentre 118.05
Bell Creek 118.05
620
790
960
253.4
32.1%
478.0
60.5%
P7G
Bell Creek 118.05
Pamour_J 118.05
620
790
960
254.6
32.2%
257.6
32.6%
P7G
Pamour_J 118.05
Hoyle_J 118.05
620
790
960
254.8
32.2%
257.8
32.6%
P7G
Hoyle_J 118.05
Kinross_J 118.05
620
790
960
178.7
22.6%
180.5
22.8%
P7G
Kinross_J 118.05
Ecstall_J 118.05
620
790
960
126.6
16.0%
127.6
16.2%
P7G
Ecstall_J 118.05
KD_CRK 118.05
1170
1430
1600
126.7
8.9%
127.7
8.9%
P7G
KD_CRK 118.05
KIDD_Metsite 118.05
1170
1430
1600
126.8
8.9%
127.7
8.9%
P13T
Porcupine TS 118.05
Timmins_K1 118.05
890
1060
1150
316.3
29.8%
326.8
30.8%
P15T
Porcupine TS 118.05
Timmins_K23 118.05
890
1140
1250
197.1
17.3%
204.4
17.9%
H6T
Hunta_SS 118.05
Tisdale_J 118.05
500
530
530
399.3
75.3%
411.0
77.5%
H6T
Tisdale_J 118.05
Laforest_RDJ 118.05
500
530
530
396.6
74.8%
408.3
77.0%
H6T
Laforest_RDJ 118.05
Timmins_K1 118.05
380
380
380
345.7
91.0%
357.5
94.1%
H7T
Hunta_SS 118.05
Warkus_J 118.05
500
530
530
451.7
85.2%
463.5
87.4%
H7T
Warkus_J 118.05
Timmins_K23 118.05
380
380
380
311.7
82.0%
323.4
85.1%
P91G
Ansonville 220.00
Anson_J91 220.00
1120
1440
1650
516.6
35.9%
510.8
35.5%
P91G
Anson_J91 220.00
KD_CRK_JP91 220.00
1120
1440
1650
516.9
35.9%
511.1
35.5%
P91G
KD_CRK_JP91 220.00
ERG_RES_JP91 220.00
1120
1440
1650
520.1
36.1%
514.1
35.7%
P91G
ERG_RES_JP91 220.00
Porcupine TS 220.00
1120
1440
1650
530.4
36.8%
524.1
36.4%
CAA ID 2011-425
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October 25, 2011
System Impact Assessment Report
Appendix A: Equipment Loading Results
Table A 3: Thermal Loading Assessment-Following the loss of 115 kV P13T circuit
without the
project
CIRCUIT
FROM
with the
project
Loading
(%)
Loading
(%)
Cont
Rating
LTE
Rating
STE
Rating
(A)
(A)
(A)
Loading
(A)
LTE
Loading
(A)
LTE
TO
P7G
Porcupine TS 118.05
Dome_Mine_J 118.05
850
1100
1410
357.6
32.5%
581.4
52.9%
P7G
Dome_Mine_J 118.05
GoldCentre 118.05
620
790
960
253.1
32.0%
476.7
60.3%
P7G
GoldCentre 118.05
Bell Creek 118.05
620
790
960
253.5
32.1%
476.9
60.4%
P7G
Bell Creek 118.05
Pamour_J 118.05
620
790
960
254.7
32.2%
257.1
32.5%
P7G
Pamour_J 118.05
Hoyle_J 118.05
620
790
960
254.9
32.3%
257.3
32.6%
P7G
Hoyle_J 118.05
Kinross_J 118.05
620
790
960
178.8
22.6%
180.2
22.8%
P7G
Kinross_J 118.05
Ecstall_J 118.05
620
790
960
126.7
16.0%
127.4
16.1%
P7G
Ecstall_J 118.05
KD_CRK 118.05
1170
1430
1600
126.7
8.9%
127.5
8.9%
P7G
KD_CRK 118.05
KIDD_Metsite 118.05
1170
1430
1600
126.8
8.9%
127.6
8.9%
P13T
Porcupine TS 118.05
Timmins_K1 118.05
890
1060
1150
0.0
0.0%
0.0
0.0%
P15T
Porcupine TS 118.05
Timmins_K23 118.05
890
1140
1250
389.5
34.2%
406.4
35.7%
H6T
Hunta_SS 118.05
Tisdale_J 118.05
500
530
530
324.3
61.2%
330.2
62.3%
H6T
Tisdale_J 118.05
Laforest_RDJ 118.05
500
530
530
327.5
61.8%
333.3
62.9%
H6T
Laforest_RDJ 118.05
Timmins_K1 118.05
380
380
380
254.5
67.0%
260.3
68.5%
H7T
Hunta_SS 118.05
Warkus_J 118.05
500
530
530
490.3
92.5%
503.5
95.0%
H7T
Warkus_J 118.05
Timmins_K23 118.05
380
380
380
353.8
93.1%
367.6
96.7%
P91G
Ansonville 220.00
Anson_J91 220.00
1120
1440
1650
533.7
37.1%
531.2
36.9%
P91G
Anson_J91 220.00
KD_CRK_JP91 220.00
1120
1440
1650
533.9
37.1%
531.5
36.9%
P91G
KD_CRK_JP91 220.00
ERG_RES_JP91 220.00
1120
1440
1650
537.0
37.3%
534.6
37.1%
P91G
ERG_RES_JP91 220.00
Porcupine TS 220.00
1120
1440
1650
546.8
38.0%
544.4
37.8%
CAA ID 2011-425
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October 25, 2011
System Impact Assessment Report
Appendix A: Equipment Loading Results
Table A 4: Thermal Loading Assessment-Following the loss of 115 kV P15T circuit
without the
project
CIRCUIT
FROM
with the
project
Loading
(%)
Loading
(%)
Cont
Rating
LTE
Rating
STE
Rating
(A)
(A)
(A)
Loading
(A)
LTE
Loading
(A)
LTE
TO
P7G
Porcupine TS 118.05
Dome_Mine_J 118.05
850
1100
1410
356.3
32.4%
581.9
52.9%
P7G
Dome_Mine_J 118.05
GoldCentre 118.05
620
790
960
252.3
31.9%
477.0
60.4%
P7G
GoldCentre 118.05
Bell Creek 118.05
620
790
960
252.6
32.0%
477.3
60.4%
P7G
Bell Creek 118.05
Pamour_J 118.05
620
790
960
253.8
32.1%
257.3
32.6%
P7G
Pamour_J 118.05
Hoyle_J 118.05
620
790
960
254.0
32.2%
257.5
32.6%
P7G
Hoyle_J 118.05
Kinross_J 118.05
620
790
960
178.3
22.6%
180.3
22.8%
P7G
Kinross_J 118.05
Ecstall_J 118.05
620
790
960
126.4
16.0%
127.5
16.1%
P7G
Ecstall_J 118.05
KD_CRK 118.05
1170
1430
1600
126.5
8.8%
127.6
8.9%
P7G
KD_CRK 118.05
KIDD_Metsite 118.05
1170
1430
1600
126.5
8.8%
127.6
8.9%
P13T
Porcupine TS 118.05
Timmins_K1 118.05
890
1060
1150
430.0
40.6%
436.2
41.2%
P15T
Porcupine TS 118.05
Timmins_K23 118.05
890
1140
1250
0.0
0.0%
0.0
0.0%
H6T
Hunta_SS 118.05
Tisdale_J 118.05
500
530
530
405.5
76.5%
419.1
79.1%
H6T
Tisdale_J 118.05
Laforest_RDJ 118.05
500
530
530
401.8
75.8%
415.5
78.4%
H6T
Laforest_RDJ 118.05
Timmins_K1 118.05
380
380
380
355.1
93.4%
368.5
97.0%
H7T
Hunta_SS 118.05
Warkus_J 118.05
500
530
530
469.6
88.6%
480.4
90.6%
H7T
Warkus_J 118.05
Timmins_K23 118.05
380
380
380
296.7
78.1%
304.4
80.1%
P91G
Ansonville 220.00
Anson_J91 220.00
1120
1440
1650
518.8
36.0%
516.9
35.9%
P91G
Anson_J91 220.00
KD_CRK_JP91 220.00
1120
1440
1650
519.1
36.0%
517.1
35.9%
P91G
KD_CRK_JP91 220.00
ERG_RES_JP91 220.00
1120
1440
1650
522.1
36.3%
520.2
36.1%
P91G
ERG_RES_JP91 220.00
Porcupine TS 220.00
1120
1440
1650
532.1
37.0%
530.3
36.8%
CAA ID 2011-425
29
October 25, 2011
System Impact Assessment Report
Appendix A: Equipment Loading Results
Table A 5: Thermal Loading Assessment-Following the loss of 115 kV H6T circuit
without the
project
CIRCUIT
FROM
with the
project
Loading
(%)
Loading
(%)
Cont
Rating
LTE
Rating
STE
Rating
(A)
(A)
(A)
Loading
(A)
LTE
Loading
(A)
LTE
TO
P7G
Porcupine TS 118.05
Dome_Mine_J 118.05
850
1100
1410
320.7
29.2%
543.6
49.4%
P7G
Dome_Mine_J 118.05
GoldCentre 118.05
620
790
960
216.7
27.4%
439.1
55.6%
P7G
GoldCentre 118.05
Bell Creek 118.05
620
790
960
217.0
27.5%
439.3
55.6%
P7G
Bell Creek 118.05
Pamour_J 118.05
620
790
960
218.3
27.6%
220.5
27.9%
P7G
Pamour_J 118.05
Hoyle_J 118.05
620
790
960
218.5
27.7%
220.7
27.9%
P7G
Hoyle_J 118.05
Kinross_J 118.05
620
790
960
177.9
22.5%
179.5
22.7%
P7G
Kinross_J 118.05
Ecstall_J 118.05
620
790
960
126.2
16.0%
127.1
16.1%
P7G
Ecstall_J 118.05
KD_CRK 118.05
1170
1430
1600
126.3
8.8%
127.2
8.9%
P7G
KD_CRK 118.05
KIDD_Metsite 118.05
1170
1430
1600
126.4
8.8%
127.2
8.9%
P13T
Porcupine TS 118.05
Timmins_K1 118.05
890
1060
1150
191.1
18.0%
395.0
37.3%
P15T
Porcupine TS 118.05
Timmins_K23 118.05
890
1140
1250
194.5
17.1%
232.8
20.4%
H6T
Hunta_SS 118.05
Tisdale_J 118.05
500
530
530
0.0
0.0%
400.5
75.6%
H6T
Tisdale_J 118.05
Laforest_RDJ 118.05
500
530
530
0.0
0.0%
395.3
74.6%
H6T
Laforest_RDJ 118.05
Timmins_K1 118.05
380
380
380
0.0
0.0%
355.4
93.5%
H7T
Hunta_SS 118.05
Warkus_J 118.05
500
530
530
338.4
63.9%
450.0
84.9%
H7T
Warkus_J 118.05
Timmins_K23 118.05
380
380
380
209.9
55.2%
329.2
86.6%
P91G
Ansonville 220.00
Anson_J91 220.00
1120
1440
1650
425.3
29.5%
0.0
0.0%
P91G
Anson_J91 220.00
KD_CRK_JP91 220.00
1120
1440
1650
425.6
29.6%
0.0
0.0%
P91G
KD_CRK_JP91 220.00
ERG_RES_JP91 220.00
1120
1440
1650
429.1
29.8%
0.0
0.0%
P91G
ERG_RES_JP91 220.00
Porcupine TS 220.00
1120
1440
1650
440.9
30.6%
0.0
0.0%
CAA ID 2011-425
30
October 25, 2011
System Impact Assessment Report
Appendix A: Equipment Loading Results
Table A 6: Thermal Loading Assessment-Following the loss of 115 kV H7T circuit
without the
project
CIRCUIT
FROM
with the
project
Loading
(%)
Loading
(%)
Cont
Rating
LTE
Rating
STE
Rating
(A)
(A)
(A)
Loading
(A)
LTE
Loading
(A)
LTE
TO
P7G
Porcupine TS 118.05
Dome_Mine_J 118.05
850
1100
1410
320.5
29.1%
544.2
49.5%
P7G
Dome_Mine_J 118.05
GoldCentre 118.05
620
790
960
216.6
27.4%
439.4
55.6%
P7G
GoldCentre 118.05
Bell Creek 118.05
620
790
960
216.9
27.5%
439.7
55.7%
P7G
Bell Creek 118.05
Pamour_J 118.05
620
790
960
218.1
27.6%
220.1
27.9%
P7G
Pamour_J 118.05
Hoyle_J 118.05
620
790
960
218.4
27.6%
220.3
27.9%
P7G
Hoyle_J 118.05
Kinross_J 118.05
620
790
960
177.8
22.5%
179.0
22.7%
P7G
Kinross_J 118.05
Ecstall_J 118.05
620
790
960
126.2
16.0%
126.3
16.0%
P7G
Ecstall_J 118.05
KD_CRK 118.05
1170
1430
1600
126.2
8.8%
126.4
8.8%
P7G
KD_CRK 118.05
KIDD_Metsite 118.05
1170
1430
1600
126.3
8.8%
126.5
8.8%
P13T
Porcupine TS 118.05
Timmins_K1 118.05
890
1060
1150
265.3
25.0%
261.2
24.6%
P15T
Porcupine TS 118.05
Timmins_K23 118.05
890
1140
1250
255.9
22.4%
193.3
17.0%
H6T
Hunta_SS 118.05
Tisdale_J 118.05
500
530
530
302.2
57.0%
240.3
45.3%
H6T
Tisdale_J 118.05
Laforest_RDJ 118.05
500
530
530
298.6
56.3%
236.6
44.6%
H6T
Laforest_RDJ 118.05
Timmins_K1 118.05
380
380
380
251.0
66.1%
190.2
50.1%
H7T
Hunta_SS 118.05
Warkus_J 118.05
500
530
530
0.0
0.0%
291.8
55.0%
H7T
Warkus_J 118.05
Timmins_K23 118.05
380
380
380
0.0
0.0%
165.7
43.6%
P91G
Ansonville 220.00
Anson_J91 220.00
1120
1440
1650
432.9
30.1%
382.0
26.5%
P91G
Anson_J91 220.00
KD_CRK_JP91 220.00
1120
1440
1650
433.3
30.1%
382.3
26.6%
P91G
KD_CRK_JP91 220.00
ERG_RES_JP91 220.00
1120
1440
1650
436.7
30.3%
386.3
26.8%
P91G
ERG_RES_JP91 220.00
Porcupine TS 220.00
1120
1440
1650
448.2
31.1%
400.0
27.8%
CAA ID 2011-425
31
October 25, 2011
System Impact Assessment Report
Appendix A: Equipment Loading Results
Table A 7: Thermal Loading Assessment-Following the loss of 230 kV P91G circuit
without the
project
CIRCUIT
FROM
with the
project
Loading
(%)
Loading
(%)
Cont
Rating
LTE
Rating
STE
Rating
(A)
(A)
(A)
Loading
(A)
LTE
Loading
(A)
TO
LTE
P7G
Porcupine TS 118.05
Dome_Mine_J 118.05
850
1100
1410
322.5
29.3%
544.0
49.5%
P7G
Dome_Mine_J 118.05
GoldCentre 118.05
620
790
960
217.8
27.6%
439.2
55.6%
P7G
GoldCentre 118.05
Bell Creek 118.05
620
790
960
218.1
27.6%
439.5
55.6%
P7G
Bell Creek 118.05
Pamour_J 118.05
620
790
960
219.4
27.8%
220.0
27.9%
P7G
Pamour_J 118.05
Hoyle_J 118.05
620
790
960
219.6
27.8%
220.2
27.9%
P7G
Hoyle_J 118.05
Kinross_J 118.05
620
790
960
178.7
22.6%
178.9
22.7%
P7G
Kinross_J 118.05
Ecstall_J 118.05
620
790
960
126.6
16.0%
126.3
16.0%
P7G
Ecstall_J 118.05
KD_CRK 118.05
1170
1430
1600
126.7
8.9%
126.4
8.8%
P7G
KD_CRK 118.05
KIDD_Metsite 118.05
1170
1430
1600
126.8
8.9%
126.4
8.8%
P13T
Porcupine TS 118.05
Timmins_K1 118.05
890
1060
1150
383.1
36.1%
261.3
24.7%
P15T
Porcupine TS 118.05
Timmins_K23 118.05
890
1140
1250
224.3
19.7%
193.5
17.0%
H6T
Hunta_SS 118.05
Tisdale_J 118.05
500
530
530
391.2
73.8%
240.2
45.3%
H6T
Tisdale_J 118.05
Laforest_RDJ 118.05
500
530
530
386.2
72.9%
236.4
44.6%
H6T
Laforest_RDJ 118.05
Timmins_K1 118.05
380
380
380
345.1
90.8%
190.1
50.0%
H7T
Hunta_SS 118.05
Warkus_J 118.05
500
530
530
441.2
83.2%
291.5
55.0%
H7T
Warkus_J 118.05
Timmins_K23 118.05
380
380
380
318.4
83.8%
165.6
43.6%
P91G
Ansonville 220.00
Anson_J91 220.00
1120
1440
1650
0.0
0.0%
382.0
26.5%
P91G
Anson_J91 220.00
KD_CRK_JP91 220.00
1120
1440
1650
0.0
0.0%
382.4
26.6%
P91G
KD_CRK_JP91 220.00
ERG_RES_JP91 220.00
1120
1440
1650
0.0
0.0%
386.4
26.8%
P91G
ERG_RES_JP91 220.00
Porcupine TS 220.00
1120
1440
1650
0.0
0.0%
400.0
27.8%
CAA ID 2011-425
32
October 25, 2011
System Impact Assessment Report
Appendix A: Equipment Loading Results
Table A 8: Thermal Loading Assessment-Following the loss of Porcupine 115 kV Transformer T3
without the
project
CIRCUIT
FROM
with the
project
Loading
(%)
Loading
(%)
Cont
Rating
LTE
Rating
STE
Rating
(A)
(A)
(A)
Loading
(A)
LTE
Loading
(A)
LTE
TO
P7G
Porcupine TS 118.05
Dome_Mine_J 118.05
850
1100
1410
358.2
32.6%
582.0
52.9%
P7G
Dome_Mine_J 118.05
GoldCentre 118.05
620
790
960
253.3
32.1%
477.0
60.4%
P7G
GoldCentre 118.05
Bell Creek 118.05
620
790
960
253.6
32.1%
477.3
60.4%
P7G
Bell Creek 118.05
Pamour_J 118.05
620
790
960
254.8
32.2%
256.8
32.5%
P7G
Pamour_J 118.05
Hoyle_J 118.05
620
790
960
255.0
32.3%
257.0
32.5%
P7G
Hoyle_J 118.05
Kinross_J 118.05
620
790
960
178.4
22.6%
179.6
22.7%
P7G
Kinross_J 118.05
Ecstall_J 118.05
620
790
960
126.0
15.9%
126.7
16.0%
P7G
Ecstall_J 118.05
KD_CRK 118.05
1170
1430
1600
126.1
8.8%
126.7
8.9%
P7G
KD_CRK 118.05
KIDD_Metsite 118.05
1170
1430
1600
126.1
8.8%
126.8
8.9%
P13T
Porcupine TS 118.05
Timmins_K1 118.05
890
1060
1150
348.9
32.9%
368.8
34.8%
P15T
Porcupine TS 118.05
Timmins_K23 118.05
890
1140
1250
165.2
14.5%
180.7
15.8%
H6T
Hunta_SS 118.05
Tisdale_J 118.05
500
530
530
403.9
76.2%
422.1
79.6%
H6T
Tisdale_J 118.05
Laforest_RDJ 118.05
500
530
530
401.5
75.8%
419.4
79.1%
H6T
Laforest_RDJ 118.05
Timmins_K1 118.05
380
380
380
349.7
92.0%
368.8
97.1%
H7T
Hunta_SS 118.05
Warkus_J 118.05
500
530
530
457.0
86.2%
474.8
89.6%
H7T
Warkus_J 118.05
Timmins_K23 118.05
380
380
380
316.3
83.2%
335.8
88.4%
P91G
Ansonville 220.00
Anson_J91 220.00
1120
1440
1650
510.8
35.5%
502.7
34.9%
P91G
Anson_J91 220.00
KD_CRK_JP91 220.00
1120
1440
1650
511.1
35.5%
503.0
34.9%
P91G
KD_CRK_JP91 220.00
ERG_RES_JP91 220.00
1120
1440
1650
514.1
35.7%
506.0
35.1%
P91G
ERG_RES_JP91 220.00
Porcupine TS 220.00
1120
1440
1650
523.9
36.4%
515.9
35.8%
CAA ID 2011-425
33
October 25, 2011
System Impact Assessment Report
Appendix A: Equipment Loading Results
Table A 9: Thermal Loading Assessment-Following the loss of Porcupine 115 kV transformer T4
without the
project
CIRCUIT
FROM
Loading
(%)
Cont
Rating
LTE
Rating
STE
Rating
(A)
(A)
(A)
Loading
(A)
TO
with the
project
LTE
Loading
(%)
Loading
(A)
LTE
P7G
Porcupine TS 118.05
Dome_Mine_J 118.05
850
1100
1410
358.1
32.6%
581.8
52.9%
P7G
Dome_Mine_J 118.05
GoldCentre 118.05
620
790
960
253.2
32.1%
476.8
60.4%
P7G
GoldCentre 118.05
Bell Creek 118.05
620
790
960
253.5
32.1%
477.1
60.4%
P7G
Bell Creek 118.05
Pamour_J 118.05
620
790
960
254.7
32.2%
256.7
32.5%
P7G
Pamour_J 118.05
Hoyle_J 118.05
620
790
960
254.9
32.3%
256.9
32.5%
P7G
Hoyle_J 118.05
Kinross_J 118.05
620
790
960
178.4
22.6%
179.6
22.7%
P7G
Kinross_J 118.05
Ecstall_J 118.05
620
790
960
126.0
15.9%
126.6
16.0%
P7G
Ecstall_J 118.05
KD_CRK 118.05
1170
1430
1600
126.1
8.8%
126.7
8.9%
P7G
KD_CRK 118.05
KIDD_Metsite 118.05
1170
1430
1600
126.1
8.8%
126.8
8.9%
P13T
Porcupine TS 118.05
Timmins_K1 118.05
890
1060
1150
349.0
32.9%
369.0
34.8%
P15T
Porcupine TS 118.05
Timmins_K23 118.05
890
1140
1250
165.3
14.5%
180.9
15.9%
H6T
Hunta_SS 118.05
Tisdale_J 118.05
500
530
530
403.9
76.2%
422.0
79.6%
H6T
Tisdale_J 118.05
Laforest_RDJ 118.05
500
530
530
401.4
75.7%
419.2
79.1%
H6T
Laforest_RDJ 118.05
Timmins_K1 118.05
380
380
380
349.7
92.0%
368.8
97.0%
H7T
Hunta_SS 118.05
Warkus_J 118.05
500
530
530
456.9
86.2%
474.7
89.6%
H7T
Warkus_J 118.05
Timmins_K23 118.05
380
380
380
316.3
83.2%
335.8
88.4%
P91G
Ansonville 220.00
Anson_J91 220.00
1120
1440
1650
510.8
35.5%
502.7
34.9%
P91G
Anson_J91 220.00
KD_CRK_JP91 220.00
1120
1440
1650
511.1
35.5%
503.0
34.9%
P91G
KD_CRK_JP91 220.00
ERG_RES_JP91 220.00
1120
1440
1650
514.1
35.7%
506.1
35.1%
P91G
ERG_RES_JP91 220.00
Porcupine TS 220.00
1120
1440
1650
523.9
36.4%
515.9
35.8%
CAA ID 2011-425
34
October 25, 2011
System Impact Assessment Report
Appendix A: Equipment Loading Results
Table A 10: Transformer Loading-With all elements in service
without the project
STATION
NAME
TRANSFORMER
ID
Cont
Rating
(MVA)
LTE
Rating
(MVA)
LOAD
(MVA)
Porcupine TS
T3
225
225
Porcupine TS
T4
225
225
with the project
Loading
(%)
Loading
(%)
Cont
LOAD
(MVA)
76.1
33.8
94.0
41.8
75.8
33.7
93.7
41.7
Cont
Table A 11: Transformer Loading-Following the loss of Porcupine SVC
without the project
STATION
NAME
TRANSFORMER
ID
Cont
Rating
(MVA)
LTE
Rating
(MVA)
LOAD
(MVA)
Porcupine TS
T3
225
225
Porcupine TS
T4
225
225
Loading
(%)
with the project
Loading
(%)
LTE
LOAD
(MVA)
75.3
33.5
94.2
41.9
75.1
33.4
93.9
41.7
LTE
Table A 12: Transformer Loading-Following the loss of 115 kV P13T circuit
without the project
STATION
NAME
TRANSFORMER
ID
Cont
Rating
(MVA)
LTE
Rating
(MVA)
LOAD
(MVA)
Porcupine TS
T3
225
225
Porcupine TS
T4
225
225
Loading
(%)
with the project
Loading
(%)
LTE
LOAD
(MVA)
65.7
29.2
86.3
38.4
65.5
29.1
86.0
38.2
LTE
Table A 13: Transformer Loading-Following the loss of 115 kV P15T circuit
without the project
STATION
NAME
TRANSFORMER
ID
Cont
Rating
(MVA)
Porcupine TS
T3
225
225
Porcupine TS
T4
225
225
CAA ID 2011-425
LTE
Rating
(MVA)
LOAD
(MVA)
35
Loading
(%)
with the project
Loading
(%)
LTE
LOAD
(MVA)
67.7
30.1
85.6
38.0
67.5
30.0
85.3
37.9
LTE
October 25, 2011
System Impact Assessment Report
Appendix A: Equipment Loading Results
Table A 14: Transformer Loading-Following the loss of 115 kV H6T circuit
without the project
STATION
NAME
TRANSFORMER
ID
Cont
Rating
(MVA)
LTE
Rating
(MVA)
LOAD
(MVA)
Porcupine TS
T3
225
225
Porcupine TS
T4
225
225
with the project
Loading
(%)
Loading
(%)
LTE
LOAD
(MVA)
77.9
34.6
108.2
48.1
77.7
34.5
107.8
47.9
LTE
Table A 15: Transformer Loading-Following the loss of 115 kV H7T circuit
without the project
STATION
NAME
TRANSFORMER
ID
Cont
Rating
(MVA)
LTE
Rating
(MVA)
LOAD
(MVA)
Porcupine TS
T3
225
225
Porcupine TS
T4
225
225
Loading
(%)
with the project
Loading
(%)
LTE
LOAD
(MVA)
72.6
32.3
0.0
0.0
72.3
32.2
211.4
94.0
LTE
Table A 16: Transformer Loading-Following the loss of 230 kV P91G circuit
without the project
STATION
NAME
TRANSFORMER
ID
Cont
Rating
(MVA)
LTE
Rating
(MVA)
LOAD
(MVA)
Porcupine TS
T3
225
225
Porcupine TS
T4
225
225
Loading
(%)
with the project
Loading
(%)
LTE
LOAD
(MVA)
87.5
38.9
211.5
94.0
87.2
38.8
0.0
0.0
LTE
Table A 17: Transformer Loading-Following the loss of Porcupine 115 kV transformer T3
without the project
STATION
NAME
TRANSFORMER
ID
Cont
Rating
(MVA)
Porcupine TS
T3
225
225
Porcupine TS
T4
225
225
CAA ID 2011-425
LTE
Rating
(MVA)
LOAD
(MVA)
36
Loading
(%)
with the project
Loading
(%)
LTE
LOAD
(MVA)
0.0
0.0
0.0
0.0
157.3
69.9
201.8
89.7
LTE
October 25, 2011
System Impact Assessment Report
Appendix A: Equipment Loading Results
Table A 18: Transformer Loading-Following the loss of Porcupine 115 kV transformer T4
without the project
STATION
NAME
TRANSFORMER
ID
Cont
Rating
(MVA)
LTE
Rating
(MVA)
LOAD
(MVA)
Porcupine TS
T3
225
225
Porcupine TS
T4
225
225
Loading
(%)
with the project
Loading
(%)
LTE
LOAD
(MVA)
157.4
70.0
201.9
89.7
0.0
0.0
0.0
0.0
LTE
– End of section–
CAA ID 2011-425
37
October 25, 2011
System Impact Assessment Report
Appendix B: System Voltage Assessment Results
Appendix B: System Voltage Assessment
Results
Table B 1: System Voltage Assessment Results-With all elements in service
without the project
with the project
Name
Base Voltage
(kV)
Voltage
(kV)
Voltage
(kV)
BELL CREEK 118.05
118.05
121.9
120.0
BELL CREEK H118.10
118.10
0.0
120.0
BELL CREEK L27.600
27.60
0.0
28.4
DOME_MINE 118.05
118.05
123.6
123.0
118.05
118.05
121.2
119.2
KINROSS 118.05
118.05
121.1
119.1
ECSTALL 118.05
118.05
121.0
119.1
KIDD_METSITE118.05
118.05
121.0
119.0
PORCUPINE_TS118.05
118.05
123.6
123.0
TIMMINS_K1H6118.05
118.05
122.8
122.1
TIMMINS_K23 118.05
118.05
122.9
122.3
HUNTA SS 118.05
118.05
127.5
127.2
LAFOREST 118.05
118.05
122.7
122.1
WARKUS 118.05
118.05
122.3
121.7
PORCUPINE_TS220.00
220.00
245.0
245.0
HOYLE
CAA ID 2011-425
38
October 25, 2011
System Impact Assessment Report
Appendix B: System Voltage Assessment Results
Table B 2: System Voltage Assessment Results-Following the loss of Porcupine SVC
without the project
Pre-tap action
with the project
Post-tap action
Pre-tap action
Post-tap action
Name
Base
Voltage
(kV)
Voltage
(kV)
Change
(%)
Voltage
(kV)
Change
(%)
Voltage
(kV)
Change
(%)
Voltage
(kV)
Change
(%)
BELL CREEK 118.05
118.05
122.4
0.3%
121.7
-0.1%
120.1
0.1%
120.1
0.1%
BELL CREEK H118.10
118.10
0.0
-
0.0
-
120.1
0.1%
120.1
0.1%
BELL CREEK L27.600
27.60
0.0
-
0.0
-
28.5
0.1%
28.5
0.1%
DOME_MINE 118.05
118.05
124.0
0.3%
123.4
-0.1%
123.1
0.1%
123.1
0.1%
118.05
118.05
121.6
0.4%
121.0
-0.1%
119.3
0.1%
119.4
0.1%
KINROSS 118.05
118.05
121.5
0.4%
120.9
-0.1%
119.2
0.1%
119.3
0.1%
ECSTALL 118.05
118.05
121.5
0.4%
120.9
-0.1%
119.2
0.1%
119.2
0.1%
KIDD_METSITE118.05
118.05
121.4
0.4%
120.8
-0.1%
119.1
0.1%
119.2
0.1%
PORCUPINE_TS118.05
118.05
124.0
0.3%
123.4
-0.1%
123.1
0.1%
123.1
0.1%
TIMMINS_K1H6118.05
118.05
123.2
0.3%
122.6
-0.1%
122.3
0.1%
122.3
0.1%
TIMMINS_K23 118.05
118.05
123.4
0.3%
122.8
-0.1%
122.4
0.1%
122.4
0.1%
HUNTA SS 118.05
118.05
127.7
0.2%
127.5
0.0%
127.3
0.0%
127.3
0.1%
LAFOREST 118.05
118.05
123.1
0.3%
122.6
-0.1%
122.2
0.1%
122.2
0.1%
WARKUS 118.05
118.05
122.7
0.3%
122.2
-0.1%
121.8
0.1%
121.9
0.1%
PORCUPINE_TS220.00
220.00
246.5
0.6%
246.6
0.7%
245.5
0.2%
245.5
0.2%
HOYLE
CAA ID 2011-425
39
October 25, 2011
System Impact Assessment Report
Appendix B: System Voltage Assessment Results
Table B 3: System Voltage Assessment Results-Following the loss of 115 kV P13T circuit
without the project
Pre-tap action
with the project
Post-tap action
Pre-tap action
Post-tap action
Name
Base
Voltage
(kV)
Voltage
(kV)
Change
(%)
Voltage
(kV)
Change
(%)
Voltage
(kV)
Change
(%)
Voltage
(kV)
Change
(%)
BELL CREEK 118.05
118.05
123.2
1.0%
121.7
-0.2%
121.2
1.1%
120.4
0.4%
BELL CREEK H118.10
118.10
0.0
-
0.0
-
121.3
1.1%
120.4
0.4%
BELL CREEK L27.600
27.60
0.0
-
0.0
-
28.7
1.1%
28.5
0.4%
DOME_MINE_J 118.05
118.05
124.8
1.0%
123.4
-0.2%
124.2
1.0%
123.4
0.3%
118.05
118.05
122.4
1.0%
121.0
-0.2%
120.5
1.1%
119.7
0.4%
KINROSS 118.05
118.05
122.3
1.0%
120.8
-0.2%
120.4
1.1%
119.5
0.4%
ECSTALL 118.05
118.05
122.3
1.0%
120.8
-0.2%
120.3
1.1%
119.5
0.4%
KIDD_METSITE118.05
118.05
122.2
1.0%
120.8
-0.2%
120.3
1.1%
119.4
0.4%
PORCUPINE_TS118.05
118.05
124.8
1.0%
123.4
-0.2%
124.2
1.0%
123.4
0.3%
TIMMINS_K1H6118.05
118.05
114.4
-6.8%
114.9
-6.4%
113.8
-6.8%
114.7
-6.1%
TIMMINS_K23 118.05
118.05
123.7
0.6%
122.2
-0.6%
123.0
0.6%
122.2
-0.1%
HUNTA_SS 118.05
118.05
126.4
-0.9%
126.2
-1.0%
126.1
-0.9%
126.1
-0.9%
LAFOREST 118.05
118.05
115.2
-6.1%
115.6
-5.8%
114.6
-6.1%
115.4
-5.5%
WARKUS 118.05
118.05
122.3
0.0%
121.3
-0.9%
121.7
0.0%
121.1
-0.5%
PORCUPINE_TS220.00
220.00
245.0
0.0%
245.0
0.0%
245.0
0.0%
245.0
0.0%
HOYLE
CAA ID 2011-425
40
October 25, 2011
System Impact Assessment Report
Appendix B: System Voltage Assessment Results
Table B 4: System Voltage Assessment Results-Following the loss of 115 kV P15T circuit
without the project
Pre-tap action
with the project
Post-tap action
Pre-tap action
Post-tap action
Name
Base
Voltage
(kV)
Voltage
(kV)
Change
(%)
Voltage
(kV)
Change
(%)
Voltage
(kV)
Change
(%)
Voltage
(kV)
Change
(%)
BELL CREEK 118.05
118.05
122.7
0.6%
122.2
0.2%
120.8
0.7%
120.3
0.3%
BELL CREEK H118.10
118.10
0.0
-
0.0
-
120.8
0.7%
120.3
0.3%
BELL CREEK L27.600
27.60
0.0
-
0.0
-
28.6
0.7%
28.5
0.3%
DOME MINE 118.05
118.05
124.4
0.6%
123.8
0.2%
123.7
0.6%
123.3
0.3%
HOYLE 118.05
118.05
122.0
0.6%
121.4
0.2%
120.0
0.7%
119.5
0.3%
KINROS 118.05
118.05
121.8
0.6%
121.3
0.2%
119.9
0.7%
119.4
0.3%
ECSTALL 118.05
118.05
121.8
0.6%
121.3
0.2%
119.9
0.7%
119.4
0.3%
KIDD_METSITE118.05
118.05
121.8
0.6%
121.2
0.2%
119.8
0.7%
119.3
0.3%
PORCUPINE TS1 18.05
118.05
124.4
0.6%
123.9
0.2%
123.8
0.6%
123.3
0.3%
TIMMINS_K1H6118.05
118.05
123.0
0.2%
122.6
-0.2%
122.4
0.2%
122.0
-0.1%
TIMMINS_K23 118.05
118.05
114.2
-7.1%
112.7
-8.3%
113.5
-7.2%
111.4
-8.9%
HUNTA SS 118.05
118.05
126.1
-1.1%
125.8
-1.3%
125.8
-1.1%
125.4
-1.4%
LAFOREST 118.05
118.05
122.8
0.1%
122.3
-0.3%
122.2
0.1%
121.8
-0.2%
WARKUS 118.05
118.05
115.9
-5.3%
114.8
-6.2%
115.3
-5.3%
113.7
-6.6%
PORCUPINE TS 220.00
220.00
245.0
0.0%
245.0
0.0%
245.0
0.0%
245.0
0.0%
CAA ID 2011-425
41
October 25, 2011
System Impact Assessment Report
Appendix B: System Voltage Assessment Results
Table B 5: System Voltage Assessment Results-Following the loss of 115 kV H6T circuit
without the project
Pre-tap action
with the project
Post-tap action
Pre-tap action
Post-tap action
Name
Base
Voltage
(kV)
Voltage
(kV)
Change
(%)
Voltage
(kV)
Change
(%)
Voltage
(kV)
Change
(%)
Voltage
(kV)
Change
(%)
BELL CREEK 118.05
118.05
122.4
0.4%
122.4
0.4%
117.3
-2.7%
120.9
0.3%
BELL CREEK H118.10
118.10
0.0
-
0.0
-
117.3
-2.7%
120.9
0.3%
BELL CREEK L27.600
27.60
0.0
-
0.0
-
27.8
-2.8%
28.7
0.3%
DOME MINE 118.05
118.05
123.9
0.4%
123.8
0.4%
120.1
-2.6%
123.6
0.3%
118.05
118.05
121.8
0.4%
121.8
0.4%
116.6
-2.7%
120.2
0.3%
KINROSS 118.05
118.05
121.7
0.4%
121.6
0.4%
116.5
-2.7%
120.1
0.3%
ECSTALL 118.05
118.05
121.6
0.4%
121.6
0.4%
116.4
-2.7%
120.1
0.3%
KIDD_METSITE118.05
118.05
121.6
0.4%
121.5
0.4%
116.4
-2.7%
120.0
0.3%
PORCUPINE TS118.05
118.05
123.9
0.4%
123.8
0.4%
120.1
-2.6%
123.6
0.3%
TIMMINS K1H6118.05
118.05
123.3
0.6%
123.2
0.6%
118.9
-2.9%
122.4
0.0%
TIMMINS K23 118.05
118.05
123.3
0.4%
123.2
0.4%
119.2
-2.9%
122.8
0.1%
HUNTA SS 118.05
118.05
125.1
0.7%
125.0
0.6%
119.6
-3.6%
122.9
-0.9%
PORCUPINE TS 220.00
220.00
245.0
0.0%
245.0
0.0%
245.0
0.0%
245.0
0.0%
HOYLE
CAA ID 2011-425
42
October 25, 2011
System Impact Assessment Report
Appendix B: System Voltage Assessment Results
Table B 6: System Voltage Assessment Results-Following the loss of 115 kV H7T circuit
without the project
Pre-tap action
with the project
Post-tap action
Pre-tap action
Post-tap action
Name
Base
Voltage
(kV)
Voltage
(kV)
Change
(%)
Voltage
(kV)
Change
(%)
Voltage
(kV)
Change
(%)
Voltage
(kV)
Change
(%)
BELL CREEK 118.05
118.05
122.5
0.5%
122.5
0.5%
113.6
-5.7%
120.6
0.1%
BELL CREEK H118.10
118.10
0.0
-
0.0
-
113.6
-5.7%
120.6
0.1%
BELL CREEK L27.600
27.60
0.0
-
0.0
-
26.9
-5.9%
28.6
0.1%
DOME MINE 118.05
118.05
124.0
0.5%
123.9
0.5%
116.5
-5.5%
123.3
0.0%
118.05
118.05
121.9
0.5%
121.8
0.5%
112.9
-5.8%
119.9
0.1%
KINROSS 118.05
118.05
121.8
0.5%
121.7
0.5%
112.8
-5.8%
119.8
0.1%
ECSTALL 118.05
118.05
121.7
0.5%
121.7
0.5%
112.8
-5.8%
119.8
0.1%
KIDD_METSITE118.05
118.05
121.7
0.5%
121.6
0.5%
112.7
-5.8%
119.7
0.1%
PORCUPINE TS118.05
118.05
124.0
0.5%
123.9
0.5%
116.5
-5.5%
123.3
0.0%
TIMMINS K1H6118.05
118.05
123.2
0.5%
123.1
0.4%
115.8
-5.5%
122.4
0.0%
TIMMINS K23 118.05
118.05
123.7
0.8%
123.6
0.7%
115.9
-5.5%
122.8
0.1%
HUNTA SS 118.05
118.05
125.9
1.4%
125.7
1.2%
119.9
-3.3%
124.2
0.2%
PORCUPINE TS 220.00
220.00
245.0
0.0%
245.0
0.0%
245.0
0.0%
245.0
0.0%
HOYLE
CAA ID 2011-425
43
October 25, 2011
System Impact Assessment Report
Appendix B: System Voltage Assessment Results
Table B 7: System Voltage Assessment Results-Following the loss of 230 kV P91G circuit
without the project
Pre-tap action
with the project
Post-tap action
Pre-tap action
Post-tap action
Name
Base
Voltage
(kV)
Voltage
(kV)
Change
(%)
Voltage
(kV)
Change
(%)
Voltage
(kV)
Change
(%)
Voltage
(kV)
Change
(%)
BELL CREEK 118.05
118.05
118.7
-2.6%
121.6
-0.2%
113.7
-5.7%
120.6
0.1%
BELL CREEK H118.10
118.10
0.0
-
0.0
-
113.7
-5.7%
120.6
0.1%
BELL CREEK L27.600
27.60
0.0
-
0.0
-
26.9
-5.8%
28.6
0.1%
DOME MINE 118.05
118.05
120.2
-2.5%
123.1
-0.2%
116.6
-5.4%
123.4
0.1%
118.05
118.05
118.1
-2.6%
121.0
-0.2%
113.0
-5.7%
120.0
0.1%
KINROSS 118.05
118.05
118.0
-2.6%
120.9
-0.2%
112.9
-5.7%
119.9
0.1%
ECSTALL 118.05
118.05
117.9
-2.6%
120.8
-0.2%
112.8
-5.7%
119.8
0.1%
KIDD_METSITE118.05
118.05
117.9
-2.6%
120.8
-0.2%
112.8
-5.7%
119.8
0.1%
PORCUPINE TS118.05
118.05
120.2
-2.5%
123.1
-0.2%
116.6
-5.4%
123.4
0.1%
TIMMINS K1H6118.05
118.05
119.1
-2.8%
121.9
-0.5%
115.9
-5.4%
122.5
0.0%
TIMMINS K23 118.05
118.05
119.3
-2.8%
122.3
-0.4%
116.0
-5.4%
122.8
0.1%
HUNTA SS 118.05
118.05
119.9
-3.4%
122.8
-1.1%
120.0
-3.2%
124.2
0.2%
LAFOREST 118.05
118.05
118.6
-3.0%
121.5
-0.7%
115.8
-5.2%
122.2
0.0%
WARKUS 118.05
118.05
117.2
-3.6%
120.3
-1.1%
115.4
-5.0%
121.5
0.1%
PORCUPINE TS 220.00
220.00
245.0
0.0%
245.0
0.0%
245.0
0.0%
245.0
0.0%
HOYLE
CAA ID 2011-425
44
October 25, 2011
System Impact Assessment Report
Appendix B: System Voltage Assessment Results
Table B 8: System Voltage Assessment Results-Following the loss of Porcupine 115 kV T/F T3
without the project
Pre-tap action
with the project
Post-tap action
Pre-tap action
Post-tap action
Name
Base
Voltage
(kV)
Voltage
(kV)
Change
(%)
Voltage
(kV)
Change
(%)
Voltage
(kV)
Change
(%)
Voltage
(kV)
Change
(%)
BELL CREEK 118.05
118.05
116.9
-4.1%
121.2
-0.6%
113.6
-5.3%
120.1
0.1%
BELL CREEK H118.10
118.10
0.0
-
0.0
-
113.6
-5.3%
120.1
0.1%
BELL CREEK L27.600
27.60
0.0
-
0.0
-
26.9
-5.5%
28.5
0.1%
DOME MINE 118.05
118.05
118.6
-4.0%
122.9
-0.6%
116.7
-5.1%
123.1
0.1%
118.05
118.05
116.2
-4.2%
120.5
-0.6%
112.8
-5.4%
119.4
0.1%
KINROSS 118.05
118.05
116.0
-4.2%
120.3
-0.6%
112.7
-5.4%
119.3
0.1%
ECSTALL 118.05
118.05
116.0
-4.2%
120.3
-0.6%
112.6
-5.4%
119.2
0.1%
KIDD_METSITE118.05
118.05
115.9
-4.2%
120.2
-0.6%
112.6
-5.4%
119.2
0.1%
PORCUPINE TS118.05
118.05
118.7
-4.0%
122.9
-0.6%
116.7
-5.1%
123.1
0.1%
TIMMINS K1H6118.05
118.05
118.0
-3.9%
121.9
-0.7%
116.1
-5.0%
122.1
0.0%
TIMMINS K23 118.05
118.05
118.1
-4.0%
122.3
-0.5%
116.2
-5.0%
122.5
0.2%
HUNTA SS 118.05
118.05
125.9
-1.3%
127.2
-0.2%
125.1
-1.7%
127.2
0.0%
LAFOREST 118.05
118.05
118.2
-3.7%
121.9
-0.7%
116.4
-4.7%
122.1
0.0%
WARKUS 118.05
118.05
118.4
-3.2%
121.8
-0.4%
116.7
-4.1%
121.8
0.1%
PORCUPINE TS 220.00
220.00
245.0
0.0%
245.0
0.0%
245.0
0.0%
245.0
0.0%
HOYLE
CAA ID 2011-425
45
October 25, 2011
System Impact Assessment Report
Appendix B: System Voltage Assessment Results
Table B 9: System Voltage Assessment Results-Following the loss of Porcupine 115 kV T/F T4
without the project
Pre-tap action
with the project
Post-tap action
Pre-tap action
Post-tap action
Name
Base
Voltage
(kV)
Voltage
(kV)
Change
(%)
Voltage
(kV)
Change
(%)
Voltage
(kV)
Change
(%)
Voltage
(kV)
Change
(%)
BELL CREEK 118.05
118.05
116.9
-4.1%
121.2
-0.6%
113.6
-5.3%
120.2
0.2%
BELL CREEK H118.10
118.10
0.0
-
0.0
-
113.6
-5.3%
120.2
0.2%
BELL CREEK L27.600
27.60
0.0
-
0.0
-
26.9
-5.4%
28.5
0.2%
DOME MINE 118.05
118.05
118.7
-4.0%
122.9
-0.6%
116.8
-5.0%
123.1
0.1%
118.05
118.05
116.2
-4.1%
120.5
-0.6%
112.8
-5.4%
119.4
0.2%
KINROSS 118.05
118.05
116.1
-4.1%
120.4
-0.6%
112.7
-5.4%
119.3
0.2%
ECSTALL 118.05
118.05
116.0
-4.1%
120.3
-0.6%
112.7
-5.4%
119.3
0.2%
KIDD_METSITE118.05
118.05
116.0
-4.1%
120.3
-0.6%
112.6
-5.4%
119.2
0.2%
PORCUPINE TS118.05
118.05
118.7
-4.0%
122.9
-0.6%
116.8
-5.0%
123.2
0.1%
TIMMINS K1H6118.05
118.05
118.0
-3.9%
122.0
-0.7%
116.1
-4.9%
122.2
0.0%
TIMMINS K23 118.05
118.05
118.1
-3.9%
122.3
-0.5%
116.2
-5.0%
122.6
0.2%
HUNTA SS 118.05
118.05
125.9
-1.3%
127.3
-0.2%
125.1
-1.7%
127.2
0.0%
LAFOREST 118.05
118.05
118.2
-3.7%
121.9
-0.6%
116.4
-4.7%
122.1
0.0%
WARKUS 118.05
118.05
118.4
-3.2%
121.8
-0.4%
116.8
-4.1%
121.9
0.1%
PORCUPINE TS 220.00
220.00
245.0
0.0%
245.0
0.0%
245.0
0.0%
245.0
0.0%
HOYLE
– End of section –
CAA ID 2011-425
46
October 25, 2011
System Impact Assessment Report
Appendix C: Motor Start Studies
Appendix C: Motor Start Studies
Table C 1: Motor start study
Bus Name
BELL CREEK 118.05
BELL CREEK H118.10
BELL CREEK L27.600
DOME MINE 118.05
HOYLE
118.05
KINROSS 118.05
ECSTALL 118.05
KIDD_METSITE118.05
PORCUPINE TS118.05
TIMMINS K1H6118.05
TIMMINS K23 118.05
HUNTA SS 118.05
LAFOREST 118.05
WARKUS 118.05
PORCUPINE TS 220.00
Before Motor
Starting
After Motor
Starting
Percentage
Change
kV
kV
%
118.05
120.38
117.62
2.35
118.10
120.41
117.63
2.36
27.60
28.593
27.565
3.73
118.05
123.16
121.48
1.38
118.05
119.64
116.90
2.34
118.05
119.51
116.77
2.35
118.05
119.47
116.73
2.35
118.05
119.43
116.69
2.35
118.05
123.18
121.51
1.37
118.05
122.35
120.73
1.34
118.05
122.49
120.87
1.34
118.05
127.30
126.56
0.58
118.05
122.29
120.76
1.27
118.05
121.92
120.6
1.09
220.00
244.99
243.7
0.53
Base KV
– End of Motor Start Studies –
CAA ID 2011-425
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October 25, 2011
System Impact Assessment Report
Appendix D: Voltage Stability Analysis
Appendix D: Voltage Stability Analysis
Figure D 1:: PV Curves
Curves- Pre and Post contingency voltages in the vicinity of the project
– End of section –
CAA ID 2011-425
48
October 25, 2011