Final Report - Ontario Power Authority

Transcription

IESO_REP_0738
System Impact
Assessment
Report
Connection Assessment &
Approval Process
Issue 1.0
Final Report
CAA ID: 2010-420
Project: Green Transformation Program,
Topping Turbogenerator Project
Applicant: Domtar Pulp and Paper Products Inc.
Market Facilitation Department
Independent Electricity System Operator
August 16, 2011
System Impact Assessment Report
Document ID
IESO_REP_0738
Document Name
Issue
1.0
Reason for Issue
Final Report
Effective Date
August 16, 2011
IESO_REP_0738
Disclaimers
Green Transformation Program, Topping Turbogenerator Project
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 approval or disapproval of
the proposed connection under Chapter 4, section 6 of the Market Rules.
Approval of the proposed connection is based on information provided to the IESO by the connection
applicant and the transmitter(s) 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 the transmitter(s) at the request of the IESO. Furthermore, the connection approval is
subject to further consideration due to changes to this information, or to additional information that
may become available after the approval has been granted. 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, connection 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, you must be aware that the IESO may revise drafts of this report at any time in its sole
discretion without notice to you. 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 it is using the most recent
version of this report.
HYDRO ONE
Special Notes and Limitations of Study Results
The results reported in this study are based on the information available to Hydro One, at the time of
the study, suitable for a System Impact Assessment of a new generation or load connection 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.
Disclaimers
This study does not assess the short circuit or thermal loading impact of the proposed connection on
facilities owned by other load and generation (including OPG) customers.
In this study, short circuit adequacy is assessed only for Hydro One breakers and does not include
other Hydro One facilities. The short circuit results are only for the purpose of assessing the
capabilities of existing Hydro One breakers and identifying upgrades required to incorporate the
proposed connection. These results should not be used in the design and engineering of new facilities
for the proposed connection. The necessary data will be provided by Hydro One and discussed with
the connection proponent 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 connection 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.
Table of Contents
Table of Contents
Table of Contents...................................................................................................... i
Executive Summary ................................................................................................. 1
Description .................................................................................................................... 1
Findings ........................................................................................................................ 1
IESO’s Requirements for Connection ............................................................................ 2
Notification of Conditional Approval ............................................................................... 5
1.
Project Description .......................................................................................... 6
2.
IESO’s General Requirements......................................................................... 7
2.1
Frequency/Speed Requirements ....................................................................... 7
2.2
Reactive Power/Voltage Regulation Requirements ............................................ 7
2.3
Voltage Ride Through Requirements ................................................................. 8
2.4
2.5
Voltage Requirements ....................................................................................... 8
Connection Equipment Design Requirements.................................................... 8
2.6
Fault Level Requirement.................................................................................... 9
2.7
Protection System Requirements....................................................................... 9
2.8
2.9
Telemetry Requirements ................................................................................... 9
Revenue Metering Requirements .................................................................... 10
2.10
Reliability Standards Requirements ................................................................. 10
2.11
Restoration Participant Requirements ............................................................. 11
2.12
Facility Registration/Market Entry Requirements ............................................. 11
3.
Data Verification ............................................................................................. 12
4.
Overview of the Transmission Network ....................................................... 15
4.1
5.
Description of the Transmission Network in the Area ....................................... 15
4.1.1
Zonal demand .................................................................................... 16
4.1.2
Existing Interface limits ...................................................................... 16
4.1.3
4.1.4
Historical Power Flows at Domtar Dryden .......................................... 17
Historical Power Flows of Interfaces and Circuits............................... 17
4.1.5
Historical Voltage levels at main buses .............................................. 19
System Impact Studies .................................................................................. 21
5.1
Study Assumptions .......................................................................................... 21
5.2
Study Scenarios .............................................................................................. 21
Scenario I (S1) ................................................................................................... 21
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Table of Contents
Scenario II (S2).................................................................................................. 22
Scenario III (S3) ................................................................................................ 22
5.3
Thermal Loading Assessment ......................................................................... 23
5.4
System Voltage Assessment ........................................................................... 24
5.5
Reactive Power Assessment ........................................................................... 25
5.6
Governor Response Assessment .................................................................... 25
5.7
Protection Impact Assessment ........................................................................ 26
5.8
Short Circuit Assessment ................................................................................ 27
5.9
Transient Analysis ........................................................................................... 31
5.10
Relay Margin Assessment ............................................................................... 32
Appendix A: Market Rules Appendix 4.2 ............................................................. 34
Appendix B: Equipment Thermal Ratings ........................................................... 37
Appendix C: Thermal Loading Assessment Results .......................................... 39
Appendix D: System Voltage Assessment Results ............................................ 47
Appendix E: Transient Simulations...................................................................... 50
Appendix F: Relay Margin Results ....................................................................... 65
Appendix G: Protection Impact Assessment ...................................................... 70
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Executive Summary
Executive Summary
Description
Domtar Pulp and Paper Products Inc. is proposing to install a new 15.9 MVA backpressure topping
turbine generator (G2) within its Domtar Dryden pulp production facility. The installation of the new
generator will add approximately 10 MW to 15MW of generation alongside the existing 41.9 MVA
turbogenerator (G1). Currently, the facility consumes on average about 7 MW of load. After the
installation of the new generator, Domtar expects the facility to be capable of exporting a maximum of
2.5 MW to the IESO-controlled grid through the overhead transmission line D5D. The proposed in
service date for the generation unit is December 2011.
This assessment examined the impact of injecting 2.5 MW of generation from the Domtar Dryden
facility into the provincial grid via the 115 kV circuit D5D on the reliability of the IESO-controlled
grid.
Findings
The following conclusions are achieved based on this assessment:
(1) The proposed connection arrangement and equipment for the 15.9 MVA generator at Domtar
Dryden does not have a material adverse impact on the reliability of the IESO-controlled grid
(2) The system fault levels after the incorporation of the 15.9 MVA generator at Domtar Dryden will
not exceed the interrupting capabilities of the existing breakers on the IESO-controlled grid near
this facility.
(3) Pre-Contingency Thermal Analysis: No pre-contingency thermal overloads were identified under
high transfer east or high transfer west conditions.
(4) Post-Contingency Thermal Analysis under High Transfer East Conditions: The potential for
congestion exists on the 115 kV circuits M2D and B6M for the loss of 230 kV circuits D26A and
A21L, respectively under pre-Domtar Dryden expansion conditions. The connection of 15.9MVA
generator at Domtar Dryden may slightly increase the power flow on the circuits by up to 4% for
existing conditions.
(5) Post-Contingency Thermal Analysis under High Transfer West Conditions: The potential for
congestion exists on the 115 kV circuit K3D for the loss of the 230 kV circuit K23D under preDomtar Dryden expansion conditions. The connection of the 15.9 MVA generator at Domtar
Dryden may slightly increase the power flow on this circuit by up to 0.4% from existing
conditions.
(6) The connection applicant will be connecting in the Northwest Ontario, an area of the power
system that may experience congestion. At times, the connection applicant may be required to
curtail the level of generation within its system for reliability purposes.
(6) The maximum voltage declines were found to be within 10% pre and post-ULTC action limit.
(7) Based on the information provided by the applicant, the governor for the new 15.9 MVA generator
will result in a droop of about 5%, which is within the required range of 3% to 7%.
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Executive Summary
(8) The incorporation of the Domtar facility does not cause any material adverse impact on the
transient performance of the IESO-controlled grid.
(9) The relay margins calculated under post-contingency conditions for various monitored circuits are
sufficient with the new generator at Domtar Dryden in-service.
(10) The Protection Impact Assessment conducted by the transmitter identified the following:
•
Existing protection hardware, protection settings and telecommunication links are adequate.
•
Connection applicant must provide redundant distance protection scheme on D5D and must
be able to reliably disconnect their equipment for a fault on D5D or M2D (when supplied by
M2D).
(11) The Market Rules governing the connection of renewable generation facilities in Ontario are
currently being reviewed through the SE-91 stakeholder initiative and, therefore, new connection
requirements (in addition to those outlined in the SIA), may be imposed in the future. The
applicant is encouraged to follow developments and updates through the following link:
http://www.ieso.ca/imoweb/consult/consult_se91.asp
IESO’s Requirements for Connection
Transmitter Requirements
The following requirements are applicable to Hydro One for the incorporation of the 15.9 MVA Domtar
Dryden backpressure topping turbine generator:
(1) The transmitter is required to review the relay settings of the 115 kV circuit D5D at Dryden TS and
any other circuits affected by the new generator.
Modifications to protection relays after this SIA is finalized must be submitted to IESO as soon as
possible or at least six (6) months before any modifications are to be implemented on the existing
protection systems. Mitigation solutions to address modifications resulting in adverse impact on
reliability must be jointly developed with the applicant.
Connection Applicant Requirements
Specific Requirements: The following specific requirements are applicable to the applicant for the
incorporation of the 15.9 MVA Domtar Dryden backpressure topping turbine generator. Specific
requirements pertain to the level of reactive compensation needed, operation restrictions, Special
Protection Systems, upgrading of equipment and any project specific items not covered in the general
requirements:
(1) A directly connected generating facility must have the capability to inject or withdraw reactive
power continuously at its connection point. The amount of reactive power required is up to
33% of its rated active power at all levels of active power output except where a lesser
continually available capability is permitted by the IESO. Since the facility will inject a
maximum active power of 2.5MW, the facility would be required to have the capability provide
±0.825 Mvar of dynamic reactive power.
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Executive Summary
The IESO has determined that, for the time being, the facility is not required to have the
capability to provide dynamic reactive power at the point of connection nor control the voltage
at the point of connection as specified in Appendix 4.2 of the Market Rules. The connection
applicant, however, will need to ensure that, with the incorporation of the new generation unit,
the facility is capable of operating at a power factor range of 0.9 lagging to 0.9 leading as
measured at the defined meter point. The IESO will direct the reactive output of the facility to
a specific value within its capability during operations as system conditions require.
It should be noted that, should system conditions in the area change in the future, the IESO may
require that the facility provide dynamic reactive power and control the voltage at the point of
connection.
(2) Under normal operating conditions, the connection applicant must ensure that the facility does
not inject more than 2.5 MW into the grid. The connection applicant must contact the IESO for
a new System Impact Assessment should an injection greater than 2.5 MW be required in the
future.
Should abnormal operating conditions arise in which the injection could momentarily exceed
2.5 MW, the connection applicant must immediately return the injection to 2.5 MW or less
within 15 minutes of occurrence. If future IESO monitoring show injections exceeding 2.5
MW for durations greater than 15 minutes, additional studies, requirements and/or possible
disconnection of the facility may result.
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 requirements summarize some of the general requirements that are applicable to the proposed
project, and presented in section 2 of this report.
(1) The connection applicant shall ensure that the facility has the capability to operate continuously
between 59.4Hz and 60.6Hz and for a limited period of time in the region above straight lines
on a log-linear scale defined by the points (0.0s, 57.0Hz), (3.3s, 57.0Hz), and (300s, 59.0Hz).
The facility shall regulate speed with an average droop based on maximum active power
adjustable between 3% and 7% and set at 4%. Regulation deadband shall not be wider than ±
0.06%. Speed shall be controlled in a stable fashion in both interconnected and island
operation. A sustained 10% change of rated active power after 10 s in response to a constant
rate of change of speed of 0.1%/s during interconnected operation shall be achievable.
(2) The connection applicant shall ensure that the facility has the capability to:
•
Supply continuously all levels of active power output for 5% deviations in terminal voltage.
•
Output reactive power as indicated in (1) under the Specific Connection Applicant
requirements above.
(3) The generation facility shall have the capability to ride through routine switching events and
design criteria contingencies assuming standard fault detection, auxiliary relaying,
communication, and rated breaker interrupting times unless disconnected by configuration.
(4) 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
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Executive Summary
continuous value and 105% of the maximum continuous value specified in Appendix 4.1of the
Market Rules.
(5) 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.
(6) The connection applicant shall ensure that the new equipment at the facility be 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.
(7) The connection applicant shall ensure that the new protection systems at the facility are
designed to satisfy all the requirements of the Transmission System Code and any additional
requirements identified by the transmitter.
The connection applicant shall have adequate provision in the design of protections and
controls at the facility to allow for future installation of Special Protection Scheme (SPS)
equipment.
The protection systems within the generation facility must only trip the appropriate equipment
required to isolate the fault.
The autoreclosure of the high voltage breakers at the connection point must be blocked. Upon
its opening for a contingency, the high voltage breaker must be closed only after the IESO
approval is granted.
Any modifications made to protection relays by the transmitter after this SIA is finalized must
be submitted to the IESO as soon as possible or at least six (6) months before any modifications
are to be implemented on the existing protection systems.
(8) 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.
(9) If revenue metering equipment is being installed as part of this project, the connection applicant
should be aware that revenue metering installations must comply with Chapter 6 of the IESO
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.
(10) The proposed facility 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
(11) Domtar Dryden is currently a restoration participant. The connection applicant is required to
update its restoration participant attachment to include details regarding its proposed project.
For more details please refer to the Market Manual 7.8. Details regarding restoration
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Executive Summary
participant requirements will be finalized at the Facility Registration/Market Entry Stage.
(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.
Notification of Conditional Approval
The proposed connection of the 15.9 MVA generator within the Domtar Dryden facility resulting in a
maximum net injection of 2.5 MW to the IESO controlled grid is expected to have no material adverse
impact on the reliability of the integrated power system, subject to the requirements specified in this
report.
It is recommended that a Notification of Conditional Approval for the addition of the 15.9 MVA
generation unit be issued to Domtar Pulp and Paper Products Inc., subject to the implementation of the
requirements outlined in this report.
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1.
Project Description
Project Description
The Domtar Dryden facility is a grid connected load facility that produces market pulp and has a
maximum load of approximately 30 MW. Currently, the facility has an existing 41.9 MVA steam
turbine generator (G1). In 2004, a new black liquor recovery boiler was installed at the plant. This
boiler is capable of generating steam at a pressure higher than a level that can be used by existing
steam turbine generator. In order for the pressure to be suitable for the existing steam turbine
generator, the recovery boiler is operated at a reduced energy level and the steam pressure is reduced
by a steam conditioning valve. Due to this constraint, the existing generator can only produce a
maximum output of 22.4 MW. Currently, the facility imports about 0 to 7 MW from IESO controlled
grid with more imports during the summer months than the winter months.
Domtar Pulp and Paper Products Inc. is proposing to install a new 15.9 MVA backpressure topping
turbine generator (G2) at the 13.2 kV Bus #3 of the Domtar Dryden facility. The new turbine will
operate with inlet steam conditions of the existing black liquor recovery boiler and exhaust to the
steam system supplying the existing 41.9MVA turbogenerator. After installing the new generator,
Domtar expects that a maximum of 2.5MW will be constantly exported to the IESO-controlled grid
through the overhead transmission line D5D.
The Domtar Dryden facility is connected to Hydro One's transmission line D5D through three
115/13.2 kV step down transformers T1, T2 and T3, with the transformer T3 normally out of service.
The existing 41.9MVA generator will be set to a power factor of 0.9 to 0.95 lagging at the generator
terminal. The new 15.9 MVA generator will be set to control the power factor at the facility defined
meter point at a value between 0.9 lagging and 0.9 leading.
The proposed in service date for the generation unit is December, 2011.
– End of Section –
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2.
IESO’s General Requirements
The connection applicant shall satisfy the 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 proposed project.
2.1 Frequency/Speed Requirements
As per Appendix 4.2 of the Market Rules, the connection applicant shall ensure that the generation
facility has the capability to operate continuously between 59.4 Hz and 60.6 Hz and for a limited
period of time in the region above straight lines on a log-linear scale defined by the points (0.0 s, 57.0
Hz), (3.3 s, 57.0 Hz), and (300 s, 59.0 Hz), as shown in the following figure.
The facility has to have the capability to regulate speed with an average droop based on maximum
active power adjustable between 3% and 7% and set at 4% unless otherwise specified by the IESO.
Regulation deadband shall not be wider than ± 0.06%. Speed shall be controlled in a stable fashion in
both interconnected and island operation. A sustained 10% change of rated active power after 10 s in
response to a constant rate of change of speed of 0.1%/s during interconnected operation shall be
achievable. Due consideration will be given to inherent limitations such as mill points and gate limits
when evaluating active power changes. Control systems that inhibit governor response shall not be
enabled without IESO approval.
2.2 Reactive Power/Voltage Regulation Requirements
The generation facilities directly connected to the IESO-controlled grid should be capable to:
•
Supply continuously all levels of active power output for 5% deviations in terminal voltage. Rated
active power is the smaller output at either rated ambient conditions (e.g. temperature, head, wind
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speed, solar radiation) or 90% of rated apparent power. To satisfy steady-state reactive power
requirements, active power reductions to rated active power are permitted.
•
Inject or withdraw reactive power continuously (i.e. dynamically) at a connection point up to 33%
of its rated active power at all levels of active power output except where a lesser continually
available capability is permitted by the IESO. If necessary, shunt capacitors must be installed to
offset the reactive power losses within the facility in excess of the maximum allowable losses. If
generators do not have dynamic reactive power capabilities, dynamic reactive compensation
devices must be installed to make up the deficient reactive power.
•
Regulate automatically voltage within ±0.5% of any set point within ±5% of rated voltage at a
point whose impedance (based on rated apparent power and rated voltage) is not more than 13%
from the highest voltage terminal. If the AVR target voltage is a function of reactive output, the
slope ∆V/∆Qmax shall be adjustable to 0.5%. The equivalent time constants shall not be longer
than 20 ms for voltage sensing and 10 ms for the forward path to the exciter output. AVR
reference compensation shall be adjustable to within 10% of the unsaturated direct axis reactance
on the unit side from a bus common to multiple units.
Please refer to Section 5.5 of this report for specific reactive power and voltage regulation
requirements for Domtar Dryden facility.
2.3 Voltage Ride Through Requirements
The generation facility shall have the capability to ride through routine switching events and design
criteria contingencies assuming standard fault detection, auxiliary relaying, communication, and rated
breaker interrupting times unless disconnected by configuration.
2.4 Voltage Requirements
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.
2.5 Connection Equipment Design Requirements
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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2.6 Fault Level Requirement
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 are 50 kA.
Fault interrupting devices must be able to interrupt fault currents at the maximum continuous voltage
of 132 kV.
2.7 Protection System Requirements
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.
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 protection systems within the generation facility must only trip the appropriate equipment
required to isolate the fault. After the facility begins commercial operation, if an improper trip of the
115 kV circuit D5D occurs due to events within the facility, the facility may be required to be
disconnected from the IESO-controlled grid until the problem is resolved.
The autoreclosure of the high voltage breakers at the connection point must be blocked. Upon its
opening for a contingency, the high voltage breaker must be closed only after the IESO approval is
granted.
Any modifications made to protection relays by the transmitter after this SIA is finalized must be
submitted to the IESO as soon as possible or at least six (6) months before any modifications are to be
implemented on the existing protection systems. If those modifications result in adverse impacts, the
connection applicant and the transmitter must develop mitigation solutions
2.8 Telemetry Requirements
If applicable according to Section 7.3 of Chapter 4 of the Market Rules, the connection applicant 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
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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.
2.9 Revenue Metering Requirements
If revenue metering equipment is being installed as part of this project, the connection applicant
should be aware that revenue metering installations must comply with Chapter 6 of the IESO 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.
2.10
Reliability Standards Requirements
Prior to connecting to the IESO controlled grid, the proposed facility 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 [email protected] 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 [email protected]. The RSSC webpage is located at:
http://www.ieso.ca/imoweb/consult/consult_rssc.asp.
CAA ID 2010-420
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August 16, 2011
2.11
Restoration Participant Requirements
The connection applicant is currently a restoration participant. The connection applicant is required to
update its restoration participant attachment to include details regarding its proposed project. For
more details please refer to the Market Manual 7.8. Details regarding restoration participant
requirements will be finalized at the Facility Registration/Market Entry Stage.
2.12
Facility Registration/Market Entry Requirements
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 to the
satisfaction of the IESO. Until this evidence is provided and found acceptable to 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.
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August 16, 2011
3.
Data Verification
Data Verification
The dynamic models of the generator, governor and excitation are given below:
1) Generator Model
The generator is represented by the Salient Pole Generator model (GENSAL) with the following
parameters and values:
Model: GENSAL – Generator Parameters
Parameter
Value
f
60
Speed
1800
MVABase
15.884
Vrated
13.8
pf
0.9
Ra
0.2267
Rf
0.2483
If-base
522
Vf-base
123
Model: GENSAL – Generator Parameters
Parameter
Value
T’do
4.091
T"do
0.0634
T"qo
0.3292
H
1.5796
Xd
1.921
Xq
1.744
X'd
0.306
X''d
0.2075
Xl
0.124
S(1.0)
0.2764
S(1.2)
1.0244
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Unit
Hz
RPM
MVA
kV
ohms
ohms
A
V
Unit
sec
sec
sec
p.u.
p.u.
p.u.
p.u.
p.u.
p.u.
August 16, 2011
Data Verification
2) Governor Model
The governor is represented by the IEEEG1 model with the following parameters and values:
Model: IEEEG1 – IEEE Type 1 Speed Governing Model
Parameter
Value
Unit
K
20
T1
9.9
sec
T2
3.3
sec
T3
0.3
sec
Uo
0.49
p.u./sec
Uc
-0.44
p.u./sec
p.u.
PMA X
1.02
p.u.
PMIN
0
T4
0.2
sec
K1
1
K2
0
T5
0
sec
K3
0
K4
0
T6
0
sec
K5
0
K6
0
T7
0
sec
K7
0
K8
0
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August 16, 2011
Data Verification
Exciter Model
The exciter is represented by the AC7B model with the following parameters and values:
Model: AC7B Excitation System Model
Parameter
Value
TR
0.02
KPR
19.97
KIR
39.58
KDR
0
TDR
9999
VRMAX
19.29
VRMIN
0
KPA
7.99
KIA
39.95
VAMAX
24.49
VAMIN
-24.49
KP
0
KL
10
KF1
0
KF2
1
KF3
0
TF
9999
KC
0.27
KD
0.93
KE
1
TE
0.36
VFEMAX
19.29
VEMIN
0
E1
7.91
S(E1)
0.89
E2
8.89
S(E2)
1.17
Unit
sec
p.u.
p.u.
p.u.
sec
p.u.
p.u.
p.u.
p.u.
p.u.
p.u.
p.u.
p.u.
p.u.
p.u.
p.u.
sec
p.u.
p.u.
p.u.
p.u.
p.u.
p.u.
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August 16, 2011
4.
Overview of the Transmission Network
This section of the report provides an overview of the transmission network in the vicinity of the
Domtar Dryden facility. The historical demand in the Northwest zone, the power flows through the
main circuits and voltage levels the main buses are also presented.
4.1 Description of the Transmission Network in the Area
The Domtar Dryden facility is connected to the Northwest 115kV system through the 115kV circuit
D5D connected to Dryden 115kV TS. The transmission area has several hydraulic generating stations
including Ear Falls GS and Manitou Falls GS. Figure 1 displays the transmission network in the
vicinity of Domtar Dryden facility.
Ear Falls TS
____ Defined Interfaces
____ 230kV network
Ear Falls GS
Musselwhite SS
E1C
____ 115kV network
M1M
Existing
41.9MVA
Generator
G1
Lac Suel GS
Trout Lake GS
____ Medium voltage connections
Moose Lake
TS
New
15.88MVA
Generator
G2
TEM (3)
M2D
To Birch TS
A3M
B6M
Manitou
Dryden TS
Falls
Domtar
Dryden
M3E
MacKenzie
TS
A21L
D5D
D26A
4 km
To Lakehead TS
E4D
A22L
Red Lake
Rabbit Lake TS
Atikokan GS
K23D
E2R
K3D
F1B
N93A
F25A
K7K
TWM (2)
To Kenora TS
K6F
Fort Frances
TS
K24F
TEK (1)
(1)
Transfer East of Kenora
Transfer West of MacKenzie
(3)
Transfer East of MacKenzie
(2)
Figure 1: Transmission Network in the Vicinity of Domtar Dryden facility
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4.1.1 Zonal demand
The historical hourly demand for the Northwest zone was obtained for the period between January
2010 and January 2011 and is displayed in Figure 2. The historical data show that the demand in the
Northwest zone can vary from approximately 320MW to 700MW.
The extreme weather coincident peak demand in summer 2012, based on the IESO load forecast, is
expected to be 411MW.
800
Active Power (MW)
700
600
500
400
300
01/11
12/10
11/10
09/10
08/10
07/10
06/10
04/10
03/10
02/10
12/09
11/09
200
Figure 2: Historical demand for the Northeast zone
4.1.2 Existing Interface limits
The following table summarizes a list of Northwest interfaces and their corresponding limits under fair
weather and all elements in service pre-contingency conditions given: (i) Ontario Manitoba Transfer
East (OMTE) and EWTE flows of 300 MW and 325 MW respectively and (ii) Ontario Manitoba
Transfer West (OMTW) and EWTW flows of 300 MW and 350 MW respectively.
These limits were respected in the analysis presented in Section 5 of this report.
Table 1: Summary of interface limits
Limits under
OMTE = 300 MW
and EWTE=325
MWcondintions
Limits under
OMTW = 300 MW
and EWTW=350
MW conditions
TEK- Transfer East of Kenora
(function of EWTW)
350 MW
350 MW
TWM - Transfer West of MacKenzie
(function of OMTRE)
50 MW
350 MW
TEM - Transfer East of MacKenzie
(function of OMTRE, OMTRW)
425MW
1 MW
MPFN - Minnesota Power Flow North
25 MW
50 MW
Interface
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4.1.3 Historical Power Flows at Domtar Dryden
The following graph shows the hourly average samples between Jan1 to Dec 31 2010 of the net
injection from Domtar Dryden.
5.
0.
-5.
-10.
-15.
-20.
-25.
-30.
Figure 3: Domtar Dryden Net Injection
As shown, Dryden Weyerhauser currently consumes about 0 to 15 MW. On average it consumes
about 7 MW.
4.1.4 Historical Power Flows of Interfaces and Circuits
The historical power flows through the main interfaces and circuits in the vicinity of the Domtar
Dryden facility were obtained for the period between January 1, 2010 to December 31, 2010. These
flows are displayed in Figures 4 to 8. Note, positive values indicate power flows in the direction of
the interface or out of the station.
400
400
300
Active Power (MW)
200
100
0
-100
200
100
0
-100
-200
-300
-200
Figure 4: Active power flow across TEK interface
CAA ID 2010-420
01/11
12/10
11/10
09/10
08/10
07/10
06/10
04/10
03/10
02/10
11/09
01/11
12/10
11/10
09/10
08/10
07/10
06/10
04/10
03/10
02/10
12/09
11/09
-400
12/09
Active Power (MW)
300
Figure 5: Active power flow across TWM interface
17
August 16, 2011
500
400
400
300
200
150
150
100
Figure 8: Active power flow through D26A at Dryden
TS
02/11
01/11
02/11
01/11
12/10
10/10
09/10
08/10
12/09
02/11
01/11
12/10
10/10
09/10
08/10
07/10
05/10
-200
04/10
-150
03/10
-150
01/10
-100
07/10
-100
05/10
-50
-50
04/10
0
0
03/10
50
50
01/10
100
12/09
12/10
Figure 7: Active power flow across EWTE
interface
Active Power (MW)
Active Power (MW)
Figure 6: Active power flow across TEM interface
10/10
12/09
02/11
01/11
12/10
10/10
09/10
08/10
07/10
05/10
-400
04/10
-400
03/10
-300
01/10
-300
09/10
-200
08/10
-200
-100
07/10
-100
0
05/10
0
100
04/10
100
200
03/10
200
01/10
Active Power (MW)
300
12/09
Active Power (MW)
Figure 9: Active power flow through K23D at Dryden
TS
The following can be observed:
Table 2: Summary of Historical Interface and Circuit Flows
Interface/Circuit
Historical maximum flow
Historical minimum flow
TEK interface
350 MW
-170MW
TWM interface
320 MW
-350MW
TEM interface
460 MW
-300MW
EWTE interface
325MW
-280MW
D26A at Dryden TS
150MW
-110MW
K23D at Dryden TS
110MW
-150MW
The above quantities were accounted for when determining the study scenarios and assumptions for
the System Impact Assessment. For the list of assumptions, please refer to Section 5 of this report.
CAA ID 2010-420
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August 16, 2011
4.1.5 Historical Voltage levels at main buses
The historical voltage levels at the main stations in the vicinity of the proposed project were obtained
for the period between January 2010 and January 2011 and are displayed in Figures 10 to 14.
135
270
265
260
Voltage (kV)
Voltage (kV)
131
127
123
255
250
245
240
119
235
02/11
01/11
12/10
10/10
09/10
08/10
07/10
05/10
04/10
03/10
12/09
02/11
01/11
12/10
10/10
09/10
08/10
07/10
05/10
04/10
03/10
01/10
12/09
Figure 10: Voltage at Dryden 115kV TS
01/10
230
115
Figure 11: Voltage at Dryden 230kV TS
270
260
255
250
Voltage (kV)
Voltage (kV)
260
250
240
245
240
235
230
230
225
02/11
01/11
12/10
10/10
09/10
08/10
07/10
05/10
04/10
03/10
12/09
02/11
01/11
12/10
10/10
09/10
08/10
07/10
05/10
04/10
03/10
01/10
12/09
Figure 12: Voltage at MacKenzie 230kV TS
01/10
220
220
Figure 13: Voltage at Fort Frances 230kV TS
131
Voltage (kV)
127
123
119
02/11
01/11
12/10
10/10
09/10
08/10
07/10
05/10
04/10
03/10
01/10
12/09
115
Figure 14: Voltage at Rabbit Lake 115kV SS
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August 16, 2011
The following can be observed:
Table 3: Summary of Historical Maximum and Minimum Voltages
Station
Historical maximum voltage
Historical minimum voltage
Dryden 115kV TS
128kV
119kV
Dryden 230kV TS
255kV
235kV
MacKenzie 230kV TS
252kV
232kV
Fort Francis 230kV TS
248kV
228kV
Rabbit Lake 115kV SS
128kV
120kV
The above quantities were accounted for when determining the study scenarios and assumptions for
the System Impact Assessment. For the list of assumptions, please refer to Section 5 of this report.
CAA ID 2010-420
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August 16, 2011
5.
System Impact Studies
This connection assessment was carried out to identify the effect of the proposed facility on thermal
loading of transmission interfaces in the vicinity, the system voltages for pre/post contingencies, the
ability of the facility to control voltage and the transient performance of the system.
5.1 Study Assumptions
The summer 2010 base case was used as the starting point for this assessment. The following general
assumptions were considered for setting up the base case:
• The total load and generation (including the new generator) at the Domtar Dryden facility were
adjusted to reflect the case of maximum power injection into the IESO-controlled grid (2.5MW
and 1.2MVAr).
• Thunder Bay G2 and G3 units were assumed out of service while Atikokan G1 was assumed inservice.
• The local generation in the vicinity of the Domtar Dryden facility was dispatched at the high
generation conditions to stress the basecase.
• The following projects were included in the basecase:
o Fort Frances Capacitor (CAA 2005-195)
o Longlac Refurbishment (CAA 2007-EX360)
o Dryden Capacitor (CAA 2008-352)
o Greenwich Wind Farm (CAA 2008-337)
o Kenora Power/Angle Relay Deregistration (CAA 2009-EX448)
o Trout Lake River Generation Facility (CAA 2010-390)
• Loads were represented by constant MVA loads for thermal and voltage analysis and as voltage
dependent loads with P being modeled as 50% constant current and 50% constant impedance (P α
V1.5) and Q being modeled as 100% constant impedance (Q α V2) for transient and relay margin
analysis.
5.2 Study Scenarios
To assess the impacts of the proposed project at Dryden, the following three scenarios were considered
for the thermal and voltage assessments:
Scenario I (S1)
The first scenario reflected high load and high transfers east conditions where the transfers across the
main interfaces in the Northwest zone were flowing from the west to the east. The Transfer East of
Mackenzie interface for this scenario is 425 MW, which is the limit for when the Ontario Manitoba
Transfer East flows are about 300 MW under all elements in-service. The Northwest zone demand
was scaled to 410 MW to reflect the extreme weather summer coincident peak forecast for 2012. The
Domtar Dryden facility was assumed to be injecting 2.5 MW and 1.21 Mvar (0.9 power factor) at the
point of connection.
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August 16, 2011
Scenario II (S2)
The second scenario considered high load and high transfers west conditions where the transfers
across the main interfaces in the Northwest zone were flowing from the east to the west. The Transfer
West of Mackenzie for this scenario is 346 MW which is approximately the limit under high Flow
West conditions for all elements in-service. The Northwest zone demand was scaled to 410 MW to
reflect the extreme weather summer coincident peak forecast for 2012. The Domtar Dryden facility
was assumed to be injecting 2.5 MW and 1.21 Mvar (0.9 power factor) at the point of connection.
Scenario III (S3)
The third scenario considered light load and light transfers conditions where the transfers across the
main interfaces in the Northwest zone were low and there was approximately no power exchange with
Manitoba or Minnesota. In this scenario the Northwest zone demand was scaled to 340 MW to reflect
the light load conditions. The Domtar Dryden facility was assumed to be injecting 2.5 MW and 1.21
Mvar (0.9 power factor) at the point of connection.
The power flows and voltages for the three scenarios are summarized in the table below:
Table 4: Summary of Voltage and Thermal Study Scenarios
Scenarios
S1
S2
S3
Interface Flows (positive indicates flow is in the defined interface direction)
TEK- Transfer East of Kenora
317.3 MW
-326.9 MW
-15.3 MW
TWM - Transfer West of MacKenzie
-375.1 MW
346.0 MW
22.7 MW
TEM - Transfer East of MacKenzie
425.5 MW
-304.6 MW
38.6 MW
EWTE - East West Transfer East
325.0 MW
-344.9 MW
-15.0 MW
OMTE - Ontario Manitoba Transfer East
292.2 MW
-297.8 MW
-0.0 MW
25 MW
5.2 MW
-2.5 MW
MPFN - Minnesota Power Flow North
Line Flows (positive indicates flow is out of the station)
D26A at Dryden TS
172.6 MW
-125 MW
0.6MW
K23D at Dryden TS
-128.8 MW
177.4MW
19.1 MW
E4D at Dryden TS
-75.9MW
-75.5 MW
-46.0MW
M2D at Dryden TS
49.8 MW
-30.6 MW
1.7 MW
K3D at Dryden TS
-19.0 MW
41.7 MW
9.7 MW
Dryden 115kV bus
123.3 kV
121.9 kV
123.9 kV
Dryden 230kV bus
241.7 kV
239.0 kV
247.3 kV
MacKenzie 230kV bus
245.2 kV
244.1 kV
246.1 kV
Fort Francis 230kV bus
244.2kV
242.9kV
247.2 kV
Rabbit Lake 115kV bus
123.8 kV
122.6 kV
123.2 kV
Ear Falls GS
19 MW
19 MW
16 MW
Lac Seul GS
12 MW
12 MW
8 MW
Manitou Falls GS
72 MW
72 MW
66 MW
Trout Lake GS
3.8 MW
3.8 MW
0 MW
Bus Voltages
Ear Falls Area Generation
CAA ID 2010-420
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August 16, 2011
The following are the list of thermal and voltage assessment contingencies studied for each scenario:
Table 5: Summary of Studied Contingencies for Thermal and Voltage Assessments
Scenario
Scenario I
Contingencies for Thermal
Assessment
Contingencies for Voltage
Assessment
Loss of Dryden T22
Loss of MacKenzie T3
Loss of the 230kV circuit D26A
Loss of the 230kV circuit D26A
Loss of the 230kV circuit F25A
Loss of the 230kV circuit A21L
Loss of the 230kV circuit A21L
Loss of the 230kV circuit F25A
Loss of the 115kV circuit M2D
Loss of 115kV circuit E4D
Loss of the 115kV circuit M2D
Loss of 115 kV circuit D5D+
Dryden T22 (loss of Domtar facility)
Loss of 230kV circuit K3D
Scenario II
Loss of 115kV circuit E4D
Scenario III
None
5.3 Thermal Loading Assessment
The purpose of this assessment is to determine the impacts of the proposed project on the thermal
loadings of the conductors and auto-transformers in the vicinity of the Domtar Dryden facility. The
criteria for the assessment are as follows:
a) All lines and equipment loadings shall be within their continuous ratings with all elements in
service and within their long-term emergency (LTE) ratings with any one element out of
service.
b) Immediately following contingencies, lines may be loaded up to their short-term emergency
(STE) ratings where control actions such as re-dispatch, switching, etc. are available to reduce
the loading to the long-term emergency ratings.
For overhead conductors, the continuous ratings are calculated at the lowest of the sag temperature or
93oC operating temperature at 30oC ambient temperature and 4 km/h wind speed. The LTE ratings are
calculated at the lowest of the sag temperature and 127oC operating temperature at 30oC ambient
temperature and 4 km/h wind speed. The 15-min STE ratings are calculated at the sag temperature of
the conductor at 30oC ambient temperature and 4 km/h wind speed for a pre-load equal to the
continuous ratings.
The percentage loading of the equipment is calculated as follows:
CAA ID 2010-420
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August 16, 2011
% 100
The thermal planning ratings used for existing transmission elements were obtained from Hydro One
and are presented in Appendix B.
The results for the thermal loading assessment for the studied scenarios are presented in the tables of
Appendix C where the cells have been shaded to indicate marginally acceptable thermal loadings or
thermal overloading.
The results in Table C5 show that under high transfers east (Scenario I), the loss of the 230kV circuit
D26A following a contingency may overload the 115kV circuit M2D between Dryden TS and Ignace
Junction beyond the 15-min STE rating (LTE and 15-min ratings are equal for these sections). To
determine whether this overload is an existing problem, a sensitivity test was performed for which the
net import from Domtar Dryden is 7 MW – the current typical operating point of the facility under
summer conditions. Results show that these overloads still exist and therefore represent an existing
issue. For the same scenario, Table C7 shows that the loss of the 230kV circuit A21L following a
contingency may overload the 115kV circuit B6M between Birch TS and Murillo Junction beyond the
15-min STE rating. To determine whether these overloads are an existing problem, a sensitivity test
was performed for which the net import from the Domtar Dryden is 7 MW. Results show that these
overloads would still exist and therefore represent an existing issue.
Under high transfers west (Scenario II), the results in Table C13 show that the 115kV circuit K3D
sections from Dryden to Rabbit Lake are overloaded beyond its 15-min STE rating (LTE and 15-min
ratings are equal) due to the loss of the 230kV circuit K23D following a contingency. To determine
whether these overloads are existing problem, a sensitivity test was performed for which the net
import from the Domtar Dryden is 7 MW. Results show that these overloads would still exist and
therefore represent an existing issue.
Based on these findings, the connection applicant should be aware that under certain system
conditions, the power output from the Domtar Dryden facility might be curtailed to help alleviate the
overloading problems in the area.
5.4 System Voltage Assessment
The IESO’s voltage assessment criteria require the pre-contingency voltages in northern Ontario to be
within 113 kV to 132 kV for 115 kV buses, 220 kV to 250 kV for 230 kV buses. The criteria also
require the post-contingency voltage to be within 108 kV to 132 kV for 115 kV buses, 207 kV to 250
kV for 230 kV buses. In addition, the criteria require that the post-contingency voltage changes should
remain within the following limits:
•
Percentage change in voltage before the tap changer action should not be more than 10%.
•
Percentage change in voltage after the tap changer action should not be more than 10% at the 115
kV and 230 kV buses.
The percentage change in voltage is calculated as follows:
CAA ID 2010-420
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August 16, 2011
% System Impact Studies
!" # $ !"
100
!"
The results for the system voltage assessment are presented in the tables of Appendix D. Results
show that the voltage levels and the percentage change in voltages at the monitored buses are within
the acceptable ranges for all studied scenarios. The largest percentage change in the voltage, 7.4%, is
observed under high transfers east (Scenario I) at Dryden 230kV due to the loss of F25A following a
contingency.
5.5 Reactive Power Assessment
Currently, the Domtar Dryden facility is classified as a load facility that is directly connected to the
IESO-controlled grid. The IESO requires that load facilities should have the capability to operate at a
power factor between 0.9 lagging and 0.9 leading.
After the installation of the new 15.9 MVA generation unit, the facility will inject active power into
the grid, and thus, becomes a generation facility that is directly connected to the IESO-controlled grid.
A directly connected facility must have the capability to inject and withdraw reactive power
continuously at its connection point. The amount of reactive capability required is up to 33% of its
rated active power at all levels of active power output except where a lesser continually available
capability is permitted by the IESO. Since the facility will inject a maximum active power of 2.5MW,
therefore, the facility will be required to provide ±0.825 Mvar of dynamic reactive power.
The results of the System Voltage Assessment show that the proposed project has no negative impacts
on the voltages in the area for any of the studied conditions. Moreover, the expected contribution of
the facility to the reactive power support needed in the area is not significant. Thus, the IESO does not
require the facility to provide the dynamic reactive power or to be in voltage control mode for the time
being. However, if the system conditions in the area change in the future, the IESO may require that
the Domtar Dryden facility provides the required dynamic reactive power and control the voltage at
the point of connection as specified in Appendix 4.2 of the Market Rules.
For the time being, the connection applicant has to ensure that the Domtar Dryden facility has the
capability to operate at a power factor within the range 0.9 lagging to 0.9 leading as measured at the
defined meter point after the installation of the new generation unit. Furthermore, the IESO will direct
the reactive power of the facility to a specific value within its capability during operations as system
conditions require.
5.6 Governor Response Assessment
Appendix 4.2 of the Market Rules requires that the generation units that are larger than 10 MW should
regulate speed with an average droop based on maximum active power adjustable between 3% and 7%
and set at 4% unless otherwise specified by the IESO.
The connection applicant has indicated that the governor for the new generation unit is a 1981 IEEE
type 1 turbine-governor with the model parameters displayed in Section 3.0 of this report.
CAA ID 2010-420
25
August 16, 2011
To test the performance of the governor model in PSS/E, the unit was assumed to be loaded at 50% of
its rated output and a 1% step change in the loading of the unit was applied. The governor response is
shown in Figure 15, where the droop in percent was calculated as follows:
%& '( )* # ' )*
#4.47993 102
100 100 #4.6%
+,( )* # +, )*
0.50975 # 0.5
Figure 15: Governor Response, K=20
The governor response shows a droop of about 5%, which is within the required range of 3% to 7%.
5.7 Protection Impact Assessment
A Protection Impact Assessment (PIA) was completed by Hydro One to examine the impact of the
new generation unit on the existing transmission system protections. The existing protections for D5D
at Dryden TS were described in the PIA report and the proposed protection settings were analyzed
based on preliminary fault calculation. Finally, the proposed protection solutions and requirements
were presented. A copy of the Protection Impact Assessment can be found in Appendix G of this
report.
The PIA report concluded that the present protections on D5D can accommodate the increase in
generation at the Domtar Dryden facility and will continue to function with the existing scheme for the
Dryden TS terminal. Also, the existing settings can cover the new scenario without requiring any
CAA ID 2010-420
26
August 16, 2011
change and the existing telecommunication links can be retained to maintain the existing remote trip
scheme.
The report required the connection applicant to provide redundant distance protection scheme to cover
faults on D5D (and on the alternate supply M2D when supplied by M2D). The report also required the
connection applicant to reliably disconnect their equipment for a fault on D5D (or M2D), even in case
that a single contingency failure occurs in their P&C systems.
5.8 Short Circuit Assessment
Fault level studies were completed by Hydro One to examine the effects of the new Domtar Dryden
15.9 MVA generator on fault levels at existing facilities in the area. Studies were performed to analyze
the fault levels with and without the new Domtar Dryden 15.9 MVA generator and other committed
generation in the surrounding area. The short circuit study was carried out with the following facilities
and system assumptions:
Niagara, South West, West Zones
•
•
•
•
•
•
•
•
•
•
All hydraulic generation
6 Nanticoke
2 Lambton
Brighton Beach (J20B/J1B)
Greenfield Energy Centre (Lambton SS)
St. Clair Energy Centre (L25N & L27N)
East Windsor Cogen (E8F & E9F) + existing Ford generation
TransAlta Sarnia (N6S/N7S)
Imperial Oil (N6S/N7S)
Thorold GS (Q10P)
Central, East Zones
•
•
•
•
•
•
•
•
•
All hydraulic generation
6 Pickering units
4 Darlington units
4 Lennox units
GTAA (44 kV buses at Bramalea TS and Woodbridge TS)
Sithe Goreway GS (V41H/V42H)
Portlands GS (Hearn SS)
Kingston Cogen
TransAlta Douglas (44 kV buses at Bramalea TS)
Northwest, Northeast Zones
• All hydraulic generation
• 1 Atikokan
CAA ID 2010-420
27
August 16, 2011
•
•
•
•
•
•
•
•
2 Thunder Bay
NP Iroquois Falls
AP Iroquois Falls
Kirkland Lake
1 West Coast (G2)
Lake Superior Power
Terrace Bay Pulp STG1 (embedded in Neenah paper)
AbiBow – No.6 Condensing Turbine
Bruce Zone
• 8 Bruce units (Bruce G1 and Bruce G2 maximum capacity @ 835 MW)
• 4 Bruce B Standby Generators
All constructed wind farms including
•
•
•
•
•
•
•
•
Erie Shores WGS (WT1T)
Kingsbridge WGS (embedded in Goderich TS)
Amaranth WGS – Amaranth I (B4V) & Amaranth II (B5V)
Ripley WGS (B22D/B23D)
Prince I & II WGS (K24G)
Underwood (B4V/B5V)
Kruger Port Alma (C24Z)
Wolf Island (injecting into X4H)
New Generation Facilities:
Committed generation
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
Greenwich Wind Farm (M23L and M24L)
Gosfield Wind Project (K2Z)
Kruger Energy Chatham Wind Project (C24Z)
Raleigh Wind Energy Centre (C23Z)
Talbot Wind Farm (W45LC)
Greenfield South GS (R24C)
Halton Hills GS (T38B/T39B)
Oakville Generating Station (B15C/B16C)
York Energy Centre (B82V/B83V)
Island Falls (H9K)
Becker Cogeneration (M2W)
Wawatay G4 (M2W)
Beck 1 G9: increase capacity to 68.5 MVA (Beck #1 115 kV bus)
Lower Mattagami Expansion
All renewable generation projects awarded FIT contracts were included
Transmission System Configuration
CAA ID 2010-420
28
August 16, 2011
Existing system with the following upgrades:
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
Bruce x Orangeville 230 kV circuits up-rated
Burlington TS: Rebuild 115 kV switchyards
Leaside TS to Birch JCT: Build new 115 kV circuit. Birch to Bayfield: Replace 115 kV
cables.
Uprate circuits D9HS, D10S and Q11S
Hurontario SS in service with R19T+V41H open from R21T+V42H (230 kV circuits V41H
and V42H extended and connected from Cardiff TS to Hurontario SS). Hurontario SS to Jim
Yarrow 2x3km 230 kV circuits in-service
Cherrywood TS to Claireville TS: Unbundle the two 500 kV super-circuits (C551VP &
C550VP)
Allanburg x Middleport 230 kV circuits (Q35M and Q26M) installed
Claireville TS: Reterminate circuit 230 kV V1RP to Parkway V71P. Reterminate circuit 230
kV V72R to Cardiff(V41H)
One 250 Mvar (@ 250 kV) shunt capacitor bank installed at Buchanan TS
LV shunt capacitor banks installed at Meadowvale
1250 MW HVDC line ON-HQ in service
Modeling of Michigan system with short circuit equivalent provided by International
Transmission Company (ITC).
Tilbury West DS second connection point for DESN arrangement using K2Z and K6Z
Second 500kV Bruce-Milton double-circuit line in service. Double-circuit line from the Bruce
Complex to Milton TS with one circuit originating from Bruce A and the other from Bruce B
Windsor area transmission reinforcement:
• 230 kV transmission line from Sandwich JCT (C21J/C22J) to Lauzon TS
• New 230/27.6 DESN, Leamington TS, that will connect C21J and C22J and supply
part of the existing Kingsville TS load
• Replace Keith 230/115 kV T11 and T12 transformers
• 115 kV circuits J3E and J4E upgrades
Woodstock Area transmission reinforcement:
• Karn TS in service and connected to M31W & M32W at Ingersol TS
• W7W/W12W terminated at LFarge CTS
• Woodstock TS connected to Karn TS
Nanticoke and Detweiler SVCs
Series capacitors at Nobel SS in each of the 500 kV circuits X503 & X504E to provide 50%
compensation for the line reactance
Lakehead TS SVC
Porcupine TS & Kirkland Lake TS SVC
Porcupine TS: Install 2x125 Mvar shunt capacitors
Essa TS : Install 250 Mvar shunt capacitor
Hanmer TS: Install 149 Mvar shunt capacitor
Pinard TS: Install 2x30 Mvar LV shunt capacitors
Upper Mattagami expansion
Fort Frances TS: Install 22 Mvar moveable shunt capacitor
Dryden TS: Install shunt capacitors
Lower Mattagami Expansion – H22D line extension from Harmon to Kipling.
System Assumptions
CAA ID 2010-420
29
August 16, 2011
•
•
•
•
•
•
•
•
•
•
•
•
•
Lambton TS 230 kV operated open
Claireville TS 230 kV operated open
Leaside TS 230 kV operated open
Leaside TS 115 kV operated open
Middleport TS 230 kV bus operated open
Hearn SS 115 kV bus operated open – as required in the Portlands SIA
Napanee TS 230 kV operated open
Cherrywood TS north & south 230kV buses operated open
Cooksville TS 230 kV bus operated open
Richview TS 230 kV bus operated open
All capacitors in service
All tie-lines in service and phase shifters on neutral taps
Maximum voltages on the buses
The following table summarizes the symmetric and asymmetrical fault levels near the Domtar Dryden
Facility against the corresponding breaker ratings.
Table 6: Summary of Short Circuit Results
With Domtar Dryden
15.9 MVA O/S
Bus
Total Fault
Current
Symmetrical
(kA)
With Domtar Dryden
15.9 MVA I/S
Total Fault
Current
Asymmetrical
(kA)
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
3-ph
fault
L-G
3-ph
fault
L-G
Dryden 115 kV
6.298
7.663
6.940
8.693
6.529
7.890
7.199
8.957
10.50
11.40
Dryden 230 kV
4.034
4.294
4.724
5.202
4.120
4.359
4.836
5.293
63.00
70.40
Domtar Dryden 115 kV
5.681
5.780
6.371
6.248
5.923
5.945
6.674
6.428
20.0
20.1
Rabbit Lake 115 kV
7.246
7.094
7.929
7.697
7.274
7.111
7.956
7.714
10.20
11.40
Moose Lake 115 kV
5.099
4.928
5.472
5.296
5.113
4.937
5.485
5.305
6.10
6.80
Ear Falls l15 kV
2.917
3.214
3.210
3.583
2.928
3.224
3.222
3.592
10.20
11.40
The results show that fault levels in the area surrounding Domtar Dryden facility are below the
symmetrical and asymmetrical breaker ratings. Fault levels increase slightly when all the proposed
generators are in service with the highest increase at Domtar Dryden of 0.303 kA (asymmetrical
current) for a 3 phase fault.
Therefore, it can be concluded that increases in fault level due to the new Domtar Dryden 15.9 MVA
generator will not exceed the interrupting capabilities of the existing breakers on the IESO-controlled
grid.
CAA ID 2010-420
30
August 16, 2011
5.9 Transient Analysis
A transient stability analysis was performed considering faults in the Ear Falls and Dryden area with
the new 15.9 MVA generator at Domtar Dryden in-service under a High Transfer East scenario and a
High Transfer West scenario. The following LLG contingencies were tested:
In both Transfer East and Transfer West cases, Domtar load was assumed to be at 30 MW at 0.92 pf,
Domtar G1 was assumed to be operating at 17.5 MW at 0.9 pf and Domtar G2 was assumed to be
operating at 15 MW, 3.1 Mvar which would help yield an injection of 2.5 MW, -1.2 Mvar (0.9 pf) at
the defined meter point.
ID
Contingency
Voltage
(kV)
Location
LLG Fault MVA
Fault Clearing
Time (ms)1
Near
Remote
Flow East Case: TEK = 352.4 MW, TEM=473.1 MW, OMTE =292 MW
FE1
LLG Fault on E4D
115 kV
Ear Falls
195 -j1368 MVA
116 ms
916 ms
FE2
LLG Fault on E4D
115 kV
Dryden
434- j4182 MVA
116 ms
516 ms
FE3
LLG Fault on K23D
230 kV
Dryden
365 -j3139 MVA
83 ms
116 ms
FE4
LLG Fault on D26A
230 kV
Dryden
365 -j3139 MVA
83 ms
116 ms
FE5
LLG Fault on K3D
115 kV
Dryden
434 -j4182 MVA
116 ms
516 ms
FE6
LLG Fault on M2D
115 kV
Dryden
434 -j4182 MVA
116 ms
149 ms
FE7
LLG Fault on
Dryden T23
115 kV
Dryden
434 -j4182 MVA
120 ms
87 ms
Flow West Case: TWM = 350.3 MW, OMTW=300 MW
FW1
LLG Fault on E4D
115 kV
Ear Falls
195 -j1368 MVA
116 ms
916 ms
FW2
LLG Fault on E4D
115 kV
Dryden
434- j4182 MVA
116 ms
516 ms
FW3
LLG Fault on K23D
230 kV
Dryden
365 -j3139 MVA
83 ms
116 ms
FW4
LLG Fault on D26A
230 kV
Dryden
365 -j3139 MVA
83 ms
116 ms
FW5
LLG Fault on K3D
115 kV
Dryden
434 -j4182 MVA
116 ms
516 ms
FW6
LLG Fault on M2D
230 kV
Dryden
434 -j4182 MVA
116 ms
149 ms
FW7
LLG Fault on
Dryden T23
115 kV
Dryden
434 -j4182 MVA
120 ms
87 ms
Note: (1) Fault applied at t=0.1 seconds
Appendix E shows the transient responses. It can be concluded from the results that with the new
15.9 MVA generator at Domtar Dryden in-service, none of the simulated contingencies caused
transient instability or undamped oscillations.
CAA ID 2010-420
31
August 16, 2011
5.10
Relay Margin Assessment
The IESO requires the relay margin on relays whose operation would not affect the integrity of the IESO-controlled grid be at least 15 percent on
all instantaneous relays and zero percent on all timed relays having a time delay setting less than or equal to 0.4 seconds.
A relay margin analysis was performed for various contingencies within the vicinity of the Domtar Dryden facility. Plots of the apparent
impedance trajectory against the relay characteristics are shown in Appendix F. The nearest point(s) of the trajectory were located and circle(s)
depicting the boundary for a 20% relay margin were drawn around the point(s). It is assumed that if the circle does not intercept with any of the
relay characteristics, then the relay margin is greater than 20% and the criteria which is stated for a 15% margin is met. The following table
summarizes the various contingencies that were simulated, the corresponding relays that were monitored and whether relay margins were
sufficient:
Table 7: Summary of Relay Margin Results
Contingency
Voltage
Fault
Location
LLG Fault MVA
Fault Clearing
Time (ms)
Near
Remote
Flow East Case: TEK = 352.4 MW , TEM=473.1 MW, OMTE =292 MW
LLG fault on D26A
230 kV
Dryden
365.14 -j3138.90
183 ms
Mackenzie
LLG fault on A21L
230 kV
581.79 -j4520.86
183 ms
216 ms
216 ms
Mackenzie
581.79 -j4520.86
183 ms
216 ms
Lakehead
641.47 -j6206.90
183 ms
216 ms
Flow West Case: TWM = 350.3 MW, OMTW=300 MW
LLG fault on K23D
230 kV
Kenora
415.73 -j3036.48
183 ms
216 ms
183 ms
216 ms
Dryden
CAA ID 2010-420
365.14 -j3138.90
32
Monitored Relays
Relay Margin Sufficient
M2D @ Moose Lake
Yes
M2D @ Dryden
Yes
M2D @ Moose Lake
Yes
M2D @ Dryden
Yes
A22L@ Mackenzie
A22L@Lakehead
B6M @ Birch
B6M @ Moose Lake
A22L@ Mackenzie
A22L@Lakehead
B6M @ Birch
B6M @ Moose Lake
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
K3D@Rabbit Lake
K3D@Dryden
K3D@Rabbit Lake
K3D@Dryden
Yes
Yes
Yes
Yes
August 16, 2011
In all cases, sufficient relay margin was observed under high flow east and flow west conditions with
the new Domtar Dryden facility in-service.
CAA ID 2010-420
33
August 16, 2011
Appendix A: Market Rules Appendix 4.2
CAA ID 2010-420
34
August 16, 2011
Appendix 4.2 – Generation Facility
Requirements
The performance requirements set out below shall apply to generation facilities subject to a
connection assessment finalized after March 6, 2010. Performance of alternative technologies will be
compared at the point of connection to the IESO-controlled grid with that of a conforming
conventional synchronous generation unit with an equal apparent power rating to determine whether a
requirement is satisfied.
Each generation facility that was authorized to connect to the IESO-controlled grid prior to March 6,
2010 shall remain subject to the performance requirements in effect for each system at the time of its
authorization to connect to the IESO-controlled grid was granted or as agreed to by the market
participant and the IESO (i.e. the “original performance requirements”). These requirements shall
prevail until the main elements of an associated system (e.g. governor control mechanism, main
exciter) are replaced or substantially modified. At that time, the replaced or substantially modified
system shall meet the applicable performance requirements set out below. All other systems, not
affected by replacement or substantial modification, shall remain subject to the original performance
requirements.
Category
Generation facility directly connected to the IESO-controlled grid, generation
facility greater than 50 MW, or generation unit greater than 10 MW shall have the
capability to:
1. Off-Nominal
Frequency
Operate continuously between 59.4 Hz and 60.6 Hz and for a limited period of time in the
region above straight lines on a log-linear scale defined by the points (0.0 s, 57.0 Hz),
(3.3 s, 57.0 Hz), and (300 s, 59.0 Hz).
2.
Speed/Frequency
Regulation
Regulate speed with an average droop based on maximum active power adjustable
between 3% and 7% and set at 4% unless otherwise specified by the IESO. Regulation
deadband shall not be wider than ± 0.06%. Speed shall be controlled in a stable fashion
in both interconnected and island operation. A sustained 10% change of rated active
power after 10 s in response to a constant rate of change of speed of 0.1%/s during
interconnected operation shall be achievable. Due consideration will be given to inherent
limitations such as mill points and gate limits when evaluating active power changes.
Control systems that inhibit governor response shall not be enabled without IESO
approval.
3. Low Voltage
Ride Through
Ride through routine switching events and design criteria contingencies assuming
standard fault detection, auxiliary relaying, communication, and rated breaker interrupting
times unless disconnected by configuration.
Category
Generation facility directly connected to the IESO-controlled grid shall have the
capability to:
4. Active Power
Supply continuously all levels of active power output for 5% deviations in terminal voltage.
Rated active power is the smaller output at either rated ambient conditions (e.g.
temperature, head, wind speed, solar radiation) or 90% of rated apparent power. To
satisfy steady-state reactive power requirements, active power reductions to rated active
power are permitted.
5. Reactive Power
Inject or withdraw reactive power continuously (i.e. dynamically) at a connection point up
to 33% of its rated active power at all levels of active power output except where a lesser
continually available capability is permitted by the IESO. A conventional synchronous unit
with a power factor range of 0.90 lagging and 0.95 leading at rated active power
connected via a main output transformer impedance not greater than 13% based on
generator rated apparent power is acceptable.
CAA ID 2010-420
35
August 16, 2011
6. Automatic
Voltage Regulator
(AVR)
Regulate automatically voltage within ±0.5% of any set point within ±5% of rated voltage
at a point whose impedance (based on rated apparent power and rated voltage) is not
more than 13% from the highest voltage terminal. If the AVR target voltage is a function of
reactive output, the slope ∆V /∆Qmax shall be adjustable to 0.5%. The equivalent time
constants shall not be longer than 20 ms for voltage sensing and 10 ms for the forward
path to the exciter output. AVR reference compensation shall be adjustable to within 10%
of the unsaturated direct axis reactance on the unit side from a bus common to multiple
units.
7. Excitation
System
Provide (a) Positive and negative ceilings not less than 200% and 140% of rated field
voltage at rated terminal voltage and rated field current; (b) A positive ceiling not less than
170% of rated field voltage at rated terminal voltage and 160% of rated field current; (c) A
voltage response time to either ceiling not more than 50 ms for a 5% step change from
rated voltage under open-circuit conditions; and (d) A linear response between ceilings.
Rated field current is defined at rated voltage, rated active power and required maximum
continuous reactive power.
8. Power System
Stabilizer (PSS)
Provide (a) A change of power and speed input configuration; (b) Positive and negative
output limits not less than ±5% of rated AVR voltage; (c) Phase compensation adjustable
to limit angle error to within 30° between 0.2 and 2.0 Hz under conditions specified by the
IESO, and (d) Gain adjustable up to an amount that either increases damping ratio above
0.1 or elicits exciter modes of oscillation at maximum active output unless otherwise
specified by the IESO. Due consideration will be given to inherent limitations.
9. Phase
Unbalance
Provide an open circuit phase voltage unbalance not more than 1% at a connection point
and operate continuously with a phase unbalance as high as 2%.
10. Armature and
Field Limiters
Provide short-time capabilities specified in IEEE/ANSI 50.13 and continuous capability
determined by either field current, armature current, or core-end heating. More restrictive
limiting functions, such as steady state stability limiters, shall not be enabled without IESO
approval.
11. Performance
Characteristics
Exhibit connection point performance comparable to an equivalent synchronous
generation unit with characteristic parameters within typical ranges. Inertia, unsaturated
transient impedance, transient time constants and saturation coefficients shall be within
typical ranges (e.g. H > 1.2 Aero-derivative, H > 1.2 Hydraulic less than 20 MVA, H > 2.0
Hydraulic 20 MVA or larger, H > 4.0 Other synchronized units, X’d < 0.5, T’do > 2.0, and
S1.2 < 0.5) except where permitted by the IESO.
CAA ID 2010-420
36
August 16, 2011
Appendix B: Equipment Thermal Ratings
CAA ID 2010-420
37
August 16, 2011
Table B1: Thermal ratings for 230kV and 115 kV circuits
Circuit
K23D
From
Kenora TS 230kV
To
Tcpl Verm J 230kV
Ratings (Amp)
Cont
LTE
STE
880
880
880
Tcpl Verm J 230kV
Dryden TS 230kV
880
880
880
K24F
Kenora TS 230kV
Ft Frances TS 230Kv
880
1060
1140
D26A
Dryden TS 230kV
MacKenzie TS 230kV
880
880
880
F25A
Ft Frances TS 230kV
MacKenzie TS 230kV
880
880
880
A21L
MacKenzie TS 230kV
Lakehead TS 230kV
880
880
880
Rabbit Lk SS 115kV
Verm Bay DS J 115kV
470
470
470
Verm Bay DS J 115kV
Eton J 115kV
470
470
470
Eton J 115kV
Dryden TS 115kV
470
470
470
Dryden TS 115kV
Dryden J A 115kV
420
420
420
Dryden J A 115kV
Ignace J 115kV
420
420
420
Ignace J 115kV
Moose Lk TS 115kV
550
550
550
Moose Lk TS 115kV
Caland Ore J 115kV
620
740
770
Caland Ore J 115kV
Sapawe J 115kV
620
740
770
Sapawe J 115kV
Kashabowie J 115kV
430
430
430
Kashabowie J 118kV
Inco Sheb J 115kV
460
460
460
Inco Sheb J 115kV
Shabaqua J 115kV
470
470
470
Shabaqua J 115kV
Stanley J 115kV
430
430
430
Stanley J 115kV
Murillo J 115kV
430
430
430
Murillo J 115kV
Birch TS 115kV
440
440
450
Moose Lk TS 115kV
MacKenzie TS 115kV
620
790
960
K3D
M2D
B6M
A3M
Table B2: Thermal ratings for auto-transformers
Station
Dryden TS
MacKenzie TS
CAA ID 2010-420
Auto-transformer
Ratings (MVA)
Cont
LTE
STE
T22
125
197.5
264.4
T23
125
197.5
264.4
T3
125
139.3
145.5
38
August 16, 2011
Appendix C: Thermal Loading Assessment
Results
CAA ID 2010-420
39
August 16, 2011
Table C1: Thermal loading assessment for Scenario I
Scenario I
Circuit
From
To
Pre-contingency
Kenora TS 230kV
Tcpl Verm J 230kV
Amp
315.6
Tcpl Verm J 230kV
Dryden TS 230kV
311.6
35.4
K24F
Kenora TS 230kV
Ft Frances TS 230Kv
327.3
37.2
D26A
Dryden TS 230kV
MacKenzie TS 230kV
419.9
47.7
F25A
Ft Frances TS 230kV
MacKenzie TS 230kV
408.1
46.4
A21L
MacKenzie TS 230kV
Lakehead TS 230kV
437.0
49.7
Rabbit Lk SS 115kV
Verm Bay DS J 115kV
101.2
21.5
Verm Bay DS J 115kV
Eton J 115kV
94.7
20.1
Eton J 115kV
Dryden TS 115kV
90.1
19.2
Dryden TS 115kV
Dryden J A 115kV
234.7
55.9
Dryden J A 115kV
Ignace J 115kV
234.7
55.9
Ignace J 115kV
Moose Lk TS 115kV
219.2
39.9
Moose Lk TS 115kV
Caland Ore J 115kV
255.1
41.2
Caland Ore J 115kV
Sapawe J 115kV
255.1
41.1
Sapawe J 115kV
Kashabowie J 115kV
251.9
58.6
Kashabowie J 118kV
Inco Sheb J 115kV
247.8
53.9
Inco Sheb J 115kV
Shabaqua J 115kV
245.3
52.2
Shabaqua J 115kV
Stanley J 115kV
251.3
58.4
Stanley J 115kV
Murillo J 115kV
248.3
57.8
Murillo J 115kV
Birch TS 115kV
339.1
77.1
Moose Lk TS 115kV
MacKenzie TS 115kV
100.2
16.2
K23D
K3D
M2D
B6M
A3M
%L
35.9
Table C2: Thermal loading assessment for Scenario I (Continued)
Scenario I
Station
Auto-transformer
Dryden TS
MacKenzie TS
CAA ID 2010-420
40
Pre-contingency
T22
MVA
24.8
%L
19.8
T23
24.7
19.8
T3
20.7
16.6
August 16, 2011
Scenario I
Circuit
Loss of Dryden T22
From
To
Kenora TS 230kV
Tcpl Verm J 230kV
Amp
321.8
%L
36.6
Amp
309.6
%L
35.2
Tcpl Verm J 230kV
Dryden TS 230kV
317.5
36.1
305.6
34.7
K24F
Kenora TS 230kV
Ft Frances TS 230Kv
326.6
30.8
334.0
31.5
D26A
Dryden TS 230kV
MacKenzie TS 230kV
415.6
47.2
437.9
49.8
F25A
Ft Frances TS 230kV
MacKenzie TS 230kV
408.1
46.4
418.2
47.5
A21L
MacKenzie TS 230kV
Lakehead TS 230kV
436.9
49.6
426.3
48.4
Rabbit Lk SS 115kV
Verm Bay DS J 115kV
88.5
18.8
94.4
20.1
Verm Bay DS J 115kV
Eton J 115kV
83.0
17.7
87.8
18.7
Eton J 115kV
Dryden TS 115kV
78.8
16.8
83.2
17.7
Dryden TS 115kV
Dryden J A 115kV
243.5
58.0
180.9
43.1
Dryden J A 115kV
Ignace J 115kV
243.5
58.0
180.9
43.1
Ignace J 115kV
Moose Lk TS 115kV
227.4
41.3
165.1
30.0
Moose Lk TS 115kV
Caland Ore J 115kV
256.1
34.6
300.6
40.6
Caland Ore J 115kV
Sapawe J 115kV
256.1
34.6
300.6
40.6
Sapawe J 115kV
Kashabowie J 115kV
252.9
58.8
297.6
69.2
Kashabowie J 118kV
Inco Sheb J 115kV
248.8
54.1
294.2
63.9
Inco Sheb J 115kV
Shabaqua J 115kV
246.2
52.4
291.8
62.1
Shabaqua J 115kV
Stanley J 115kV
252.2
58.7
297.9
69.3
Stanley J 115kV
Murillo J 115kV
249.2
58.0
294.9
68.6
Murillo J 115kV
Birch TS 115kV
339.9
77.2
384.8
87.5
Moose Lk TS 115kV
MacKenzie TS 115kV
106.6
13.5
0.0
0.0
K23D
K3D
M2D
B6M
A3M
Scenario I
Station
Dryden TS
MacKenzie TS
CAA ID 2010-420
Auto-transformer
Loss of Dryden T22
T22
MVA
0.0
%L
0.0
MVA
29.4
%L
14.9
T23
44.9
22.7
29.4
14.9
T3
22.0
15.8
0.0
0.0
41
August 16, 2011
Scenario I
Circuit
From
Loss of D26A
To
Kenora TS 230kV
Tcpl Verm J 230kV
Amp
62.0
Tcpl Verm J 230kV
Dryden TS 230kV
64.2
7.3
82.0
9.3
K24F
Kenora TS 230kV
Ft Frances TS 230Kv
535.6
50.5
525.1
49.5
D26A
Dryden TS 230kV
MacKenzie TS 230kV
0.0
0.0
0.0
0.0
F25A
Ft Frances TS 230kV
MacKenzie TS 230kV
655.3
74.5
641.7
72.9
A21L
MacKenzie TS 230kV
Lakehead TS 230kV
392.8
44.6
384.2
43.7
Rabbit Lk SS 115kV
Verm Bay DS J 115kV
12.5
2.7
18.8
4.0
Verm Bay DS J 115kV
Eton J 115kV
11.3
2.4
12.9
2.7
Eton J 115kV
Dryden TS 115kV
15.0
3.2
13.5
2.9
Dryden TS 115kV
Dryden J A 115kV
476.7
113.5
458.9
109.3
Dryden J A 115kV
Ignace J 115kV
476.7
113.5
458.9
109.3
Ignace J 115kV
Moose Lk TS 115kV
461.3
83.9
443.8
80.7
Moose Lk TS 115kV
Caland Ore J 115kV
267.9
36.2
263.2
35.6
Caland Ore J 115kV
Sapawe J 115kV
267.9
36.2
263.1
35.6
Sapawe J 115kV
Kashabowie J 115kV
264.5
61.5
259.7
60.4
Kashabowie J 118kV
Inco Sheb J 115kV
259.6
56.4
254.5
55.3
Inco Sheb J 115kV
Shabaqua J 115kV
256.6
54.6
251.2
53.5
Shabaqua J 115kV
Stanley J 115kV
262.3
61.0
256.9
59.7
Stanley J 115kV
Murillo J 115kV
258.8
60.2
253.2
58.9
Murillo J 115kV
Birch TS 115kV
347.4
79.0
342.3
77.8
Moose Lk TS 115kV
MacKenzie TS 115kV
318.3
40.3
305.7
38.7
K23D
K3D
M2D
B6M
A3M
%L
7.0
Loss of D26A
(Domtar net load = 7MW)
Amp
%L
74.8
8.5
Scenario I
Station
Dryden TS
MacKenzie TS
CAA ID 2010-420
Loss of D26A
Auto-transformer
Loss of D26A
(Domtar net load = 7 MW)
MVA
%L
19.5
9.9
T22
MVA
15.5
%L
7.9
T23
15.6
7.9
19.5
9.9
T3
65.9
47.3
62.7
45.0
42
August 16, 2011
Scenario I
Circuit
From
Loss of A21L
To
Kenora TS 230kV
Tcpl Verm J 230kV
Amp
290.9
Tcpl Verm J 230kV
Dryden TS 230kV
287.4
32.7
290.8
33.0
K24F
Kenora TS 230kV
Ft Frances TS 230Kv
308.9
29.1
305.2
28.8
D26A
Dryden TS 230kV
MacKenzie TS 230kV
387.5
44.0
377.7
42.9
F25A
Ft Frances TS 230kV
MacKenzie TS 230kV
369.6
42.0
364.2
41.4
A21L
MacKenzie TS 230kV
Lakehead TS 230kV
0.0
0.0
0.0
0.0
Rabbit Lk SS 115kV
Verm Bay DS J 115kV
93.9
20.0
97.4
20.7
Verm Bay DS J 115kV
Eton J 115kV
87.9
18.7
92.1
19.6
Eton J 115kV
Dryden TS 115kV
83.4
17.8
87.8
18.7
Dryden TS 115kV
Dryden J A 115kV
244.2
58.1
235.6
56.1
Dryden J A 115kV
Ignace J 115kV
244.2
58.1
235.6
56.1
Ignace J 115kV
Moose Lk TS 115kV
230.2
41.8
221.0
40.2
Moose Lk TS 115kV
Caland Ore J 115kV
389.9
52.7
380.8
51.5
Caland Ore J 115kV
Sapawe J 115kV
389.9
52.7
380.8
51.5
Sapawe J 115kV
Kashabowie J 115kV
387.1
90.0
378.0
87.9
Kashabowie J 118kV
Inco Sheb J 115kV
383.8
83.4
374.6
81.4
Inco Sheb J 115kV
Shabaqua J 115kV
381.2
81.1
372.0
79.2
Shabaqua J 115kV
Stanley J 115kV
387.2
90.0
378.0
87.9
Stanley J 115kV
Murillo J 115kV
383.6
89.2
374.5
87.1
Murillo J 115kV
Birch TS 115kV
470.6
107.0
461.7
104.9
Moose Lk TS 115kV
MacKenzie TS 115kV
25.8
3.3
26.0
3.3
K23D
K3D
M2D
B6M
A3M
%L
33.1
Loss of A21L
(Domtar net power = 7 MW)
Amp
%L
293.9
33.4
Scenario I
Station
Dryden TS
MacKenzie TS
CAA ID 2010-420
Loss of A21L
Auto-transformer
Loss of A21L
(Domtar net power = 0)
MVA
%L
MVA
%L
T22
23.3
11.8
21.7
11.0
T23
23.3
11.8
21.7
11.0
T3
5.4
3.9
5.5
3.9
43
August 16, 2011
Scenario I
Circuit
Loss of F25A
Loss of M2D
From
To
Kenora TS 230kV
Tcpl Verm J 230kV
Amp
605.0
%L
68.7
Amp
281.2
%L
32.0
Tcpl Verm J 230kV
Dryden TS 230kV
606.8
69.0
277.9
31.6
K24F
Kenora TS 230kV
Ft Frances TS 230Kv
43.4
4.1
353.2
33.3
D26A
Dryden TS 230kV
MacKenzie TS 230kV
720.1
81.8
491.0
55.8
F25A
Ft Frances TS 230kV
MacKenzie TS 230kV
0.0
0.0
440.8
50.1
A21L
MacKenzie TS 230kV
Lakehead TS 230kV
395.7
45.0
440.1
50.0
Rabbit Lk SS 115kV
Verm Bay DS J 115kV
242.3
51.5
67.8
14.4
Verm Bay DS J 115kV
Eton J 115kV
237.3
50.5
63.0
13.4
Eton J 115kV
Dryden TS 115kV
232.5
49.5
59.1
12.6
Dryden TS 115kV
Dryden J A 115kV
380.4
90.6
0.0
0.0
Dryden J A 115kV
Ignace J 115kV
380.4
90.6
0.0
0.0
Ignace J 115kV
Moose Lk TS 115kV
364.5
66.3
0.0
0.0
Moose Lk TS 115kV
Caland Ore J 115kV
257.5
34.8
226.4
30.6
Caland Ore J 115kV
Sapawe J 115kV
257.5
34.8
226.4
30.6
Sapawe J 115kV
Kashabowie J 115kV
254.1
59.1
223.1
51.9
Kashabowie J 118kV
Inco Sheb J 115kV
249.4
54.2
218.6
47.5
Inco Sheb J 115kV
Shabaqua J 115kV
246.5
52.4
215.9
45.9
Shabaqua J 115kV
Stanley J 115kV
252.3
58.7
221.9
51.6
Stanley J 115kV
Murillo J 115kV
248.9
57.9
218.9
50.9
Murillo J 115kV
Birch TS 115kV
338.0
76.8
310.3
70.5
Moose Lk TS 115kV
MacKenzie TS 115kV
236.7
30.0
89.5
11.3
K23D
K3D
M2D
B6M
A3M
Scenario I
Station
Dryden TS
MacKenzie TS
CAA ID 2010-420
Loss of F25A
Auto-transformer
Loss of M2D
T22
MVA
26.3
%L
13.3
MVA
45.8
%L
23.2
T23
26.2
13.3
45.8
23.2
T3
48.7
34.9
18.6
13.3
44
August 16, 2011
Table C11: Thermal loading assessment for Scenario II
Scenario II
Circuit
From
To
Kenora TS 230kV
Pre-contingency
Loss of K3D
Tcpl Verm J 230kV
Amp
428.0
%L
48.6
Amp
503.7
%L
57.2
Tcpl Verm J 230kV
Dryden TS 230kV
432.2
49.1
508.1
57.7
K24F
Kenora TS 230kV
Ft Frances TS 230Kv
262.0
29.8
270.2
25.5
D26A
Dryden TS 230kV
MacKenzie TS 230kV
306.1
34.8
283.7
32.2
F25A
Ft Frances TS 230kV
MacKenzie TS 230kV
435.7
49.5
461.6
52.5
A21L
MacKenzie TS 230kV
Lakehead TS 230kV
347.0
39.4
343.1
39.0
Rabbit Lk SS 115kV
Verm Bay DS J 115kV
199.6
42.5
0.0
0.0
Verm Bay DS J 115kV
Eton J 115kV
202.1
43.0
0.0
0.0
Eton J 115kV
Dryden TS 115kV
206.1
43.9
0.0
0.0
Dryden TS 115kV
Dryden J A 115kV
151.3
36.0
129.8
30.9
Dryden J A 115kV
Ignace J 115kV
157.5
37.5
135.7
32.3
Ignace J 115kV
Moose Lk TS 115kV
181.1
32.9
159.8
29.1
Moose Lk TS 115kV
Caland Ore J 115kV
145.9
23.5
142.0
19.2
Caland Ore J 115kV
Sapawe J 115kV
146.2
23.6
142.2
19.2
Sapawe J 115kV
Kashabowie J 115kV
149.6
34.8
145.3
33.8
Kashabowie J 118kV
Inco Sheb J 115kV
150.4
32.7
146.0
31.7
Inco Sheb J 115kV
Shabaqua J 115kV
150.9
32.1
146.5
31.2
Shabaqua J 115kV
Stanley J 115kV
144.6
33.6
140.1
32.6
Stanley J 115kV
Murillo J 115kV
144.8
33.7
140.3
32.6
Murillo J 115kV
Birch TS 115kV
92.0
20.9
87.3
19.8
Moose Lk TS 115kV
MacKenzie TS 115kV
109.8
17.7
124.5
15.8
K23D
K3D
M2D
B6M
A3M
Table C12: Thermal loading assessment for Scenario II (Continued)
Scenario II
Station
Dryden TS
MacKenzie TS
CAA ID 2010-420
Pre-contingency
Auto-transformer
MVA
%L
T22
28.5
T23
T3
45
Loss of K3D
22.8
MVA
48.2
%L
24.4
28.5
22.8
48.2
24.4
21.57
17.3
25.3
18.2
August 16, 2011
Scenario II
Circuit
From
Loss of K23D
To
Loss of K23D
(Domtar net power = 7 MW)
Amp
%L
Amp
%L
0.0
0.0
0.0
Kenora TS 230kV
Tcpl Verm J 230kV
0.0
Tcpl Verm J 230kV
Dryden TS 230kV
0.0
0.0
0.0
0.0
K24F
Kenora TS 230kV
Ft Frances TS 230Kv
499.5
47.1
502.3
47.4
D26A
Dryden TS 230kV
MacKenzie TS 230kV
95.0
10.8
112.6
12.8
F25A
Ft Frances TS 230kV
MacKenzie TS 230kV
687.5
78.1
692.4
78.7
A21L
MacKenzie TS 230kV
Lakehead TS 230kV
337.4
38.3
348.3
39.6
Rabbit Lk SS 115kV
Verm Bay DS J 115kV
552.2
117.5
550.3
117.1
Verm Bay DS J 115kV
Eton J 115kV
553.6
117.8
551.9
117.4
Eton J 115kV
Dryden TS 115kV
557.6
118.6
555.8
118.2
Dryden TS 115kV
Dryden J A 115kV
81.0
19.3
93.0
22.1
Dryden J A 115kV
Ignace J 115kV
88.6
21.1
101.6
24.2
Ignace J 115kV
Moose Lk TS 115kV
117.8
21.4
131.4
23.9
Moose Lk TS 115kV
Caland Ore J 115kV
136.0
18.4
143.7
19.4
Caland Ore J 115kV
Sapawe J 115kV
136.1
18.4
143.8
19.4
Sapawe J 115kV
Kashabowie J 115kV
138.7
32.3
146.3
34.0
Kashabowie J 118kV
Inco Sheb J 115kV
139.2
30.3
146.7
31.9
Inco Sheb J 115kV
Shabaqua J 115kV
139.5
29.7
146.9
31.3
Shabaqua J 115kV
Stanley J 115kV
133.0
30.9
140.2
32.6
Stanley J 115kV
Murillo J 115kV
133.2
31.0
140.4
32.7
Murillo J 115kV
Birch TS 115kV
79.6
18.1
83.9
19.1
Moose Lk TS 115kV
MacKenzie TS 115kV
164.8
20.9
169.1
21.4
K23D
K3D
M2D
B6M
A3M
Scenario II
Station
Dryden TS
MacKenzie TS
CAA ID 2010-420
Loss of K23D
Auto-transformer
Loss of K23D
(Domtar net power = 0)
MVA
%L
MVA
%L
T22
22.3
11.3
27.6
14.0
T23
22.3
11.3
27.6
14.0
T3
33.3
23.9
34.1
24.4
46
August 16, 2011
Appendix D: System Voltage Assessment
Results
CAA ID 2010-420
47
August 16, 2011
Table D1: System voltage assessment for Scenario I
Scenario I
Loss of D26A
Loss of F25A
Bus Name
Precontingency
Domtar 115kV
123.4
123.4 -0.02
123.4 -0.02
120.5 2.29
122.1 1.04
118.6
3.89
122.1 0.98
Dryden 115kV
123.3
123.4 -0.02
123.4 -0.02
120.5 2.29
122.0 1.04
118.5
3.89
122.1 0.98
Dryden 230kV
241.7
241.7
0.03
241.7
0.03
235.8 2.45
232.5 3.82
231.8
4.10
223.9 7.39
Rabbit Lk 115kV
123.8
123.8
0.04
123.8
0.04
121.8 1.64
122.6 0.95
122.9
0.70
122.7 0.86
Moose Lk 115kV
119.6
120.7 -0.94
120.7 -0.94
115.7 3.25
117.3 1.90
117.0
2.13
118.1 1.23
MacKenzie 230kV
245.2
244.9
0.14
244.9
0.14
241.9 1.38
240.1 2.11
242.2
1.26
238.7 2.66
Kenora 230kV
243.0
242.9
0.05
242.9
0.05
238.0 2.06
236.0 2.91
240.3
1.11
238.0 2.06
kV
Pre-ULTC
kV
%Vch
Post-ULTC
kV
Pre-ULTC
% Vch
kV
% Vch
Post-ULTC
kV
Pre-ULTC
% Vch
kV
Post-ULTC
% Vch
kV
% Vch
Table D2: System voltage assessment for Scenario I (Continued)
Scenario I
Bus Name
Precont
Loss of A21L
Pre-ULTC
Loss of M2D
Post-ULTC
Pre-ULTC
Loss of D5D +Dryden T22
(Loss of Domtar Facility)
Loss of E4D
Post-ULTC
Pre-ULTC
Post-ULTC
Pre-ULTC
Post-ULTC
Domtar 115kV
kV
123.4
kV
123.2
%
Vch
0.15
kV
123.1
%
Vch
0.24
kV
122.3
%
Vch
0.90
kV
122.2
%
Vch
0.90
kV
124.6
%
Vch
-1.04
kV
125.0
%
Vch
-1.31
kV
N/A
%
Vch
N/A
kV
N/A
% Vch
N/A
Dryden 115kV
123.3
123.2
0.15
123.0
0.24
122.2
0.90
122.2
0.90
124.6
-1.04
125.0
-1.31
123.2
0.13
123.2
0.13
Dryden 230kV
241.7
241.4
0.12
241.2
0.22
240.0
0.73
240.0
0.74
242.7
-0.42
246.6
-2.03
241.5
0.10
241.5
0.10
Rabbit Lk 115kV
123.8
123.9
-0.06
123.8
-0.01
123.3
0.37
123.3
0.37
123.8
0.02
124.7
-0.73
123.7
0.05
123.7
0.05
Moose Lk 115kV
MacKenzie
230kV
119.6
118.1
1.20
118.0
1.30
119.4
0.09
119.4
0.09
120.5
-0.81
120.7
-0.97
119.5
0.02
119.5
0.02
245.2
242.6
1.09
242.3
1.20
244.0
0.50
244.0
0.50
246.6
-0.56
249.8
-1.84
245.2
0.02
245.2
0.02
Kenora 230kV
243.0
243.5
-0.19
243.4
-0.13
242.1
0.40
242.1
0.41
242.1
0.39
245.2
-0.87
242.9
0.06
242.9
0.06
CAA ID 2010-420
48
August 16, 2011
Table D3: System voltage assessment for Scenario II
Scenario II
Loss of D5D+Dryden T22
(Loss of Domtar Facility
Bus Name
Precontingency
Domtar 115kV
kV
121.9
kV
120.0
% Vch
1.59
kV
122.8
% Vch
-0.68
kV
120.4
% Vch
1.23
kV
121.6
% Vch
0.30
kV
N/A
% Vch
N/A
kV
N/A
% Vch
N/A
Dryden 115kV
121.9
120.0
1.59
122.7
-0.68
120.4
1.23
121.5
0.30
121.8
0.11
121.8
0.11
Dryden 230kV
239.0
235.6
1.41
234.1
2.08
236.9
0.90
236.0
1.24
238.8
0.08
238.8
0.08
Rabbit Lk 115kV
122.6
114.1
6.94
122.1
0.43
122.8
-0.18
122.6
0.01
122.5
0.03
122.5
0.03
Moose Lk 115kV
119.9
118.7
1.05
119.7
0.17
119.6
0.29
119.7
0.20
119.9
0.03
119.9
0.03
MacKenzie 230kV
244.1
240.6
1.41
239.2
1.99
243.4
0.26
243.3
0.31
244.0
0.02
244.0
0.02
Kenora 230kV
238.7
228.9
4.11
226.7
5.00
237.2
0.59
236.8
0.79
238.6
0.02
238.6
0.02
Loss of K23D
Pre-ULTC
Loss of K3D
Post-ULTC
Pre-ULTC
Post-ULTC
Pre-ULTC
Post-ULTC
Table D4: System voltage assessment for Scenario III
Scenario III
Loss of D5D+ Dryden T22
(Loss of Domtar Facility)
Loss of E4D
Bus Name
Pre-contingency
Pre-ULTC
Post-ULTC
Pre-ULTC
Post-ULTC
Domtar 115kV
kV
123.9
kV
124.7
% Vch
-0.67
kV
124.7
% Vch
-0.67
kV
N/A
% Vch
N/A
kV
N/A
% Vch
N/A
Dryden 115kV
123.9
124.7
-0.67
124.7
-0.67
123.7
0.12
123.7
0.12
Dryden 230kV
247.3
248.1
-0.34
248.1
-0.34
247.1
0.09
247.1
0.09
Rabbit Lk 115kV
123.2
123.5
-0.24
123.5
-0.25
123.2
0.03
123.2
0.03
Moose Lk 115kV
119.3
119.5
-0.23
119.5
-0.22
119.2
0.03
119.2
0.03
MacKenzie 230kV
246.1
246.4
-0.12
246.4
-0.12
246.0
0.03
246.0
0.03
Kenora 230kV
244.6
245.1
-0.23
245.1
-0.23
244.5
0.04
244.5
0.04
CAA ID 2010-420
49
August 16, 2011
Appendix E: Transient Simulations
CAA ID 2010-420
50
August 16, 2011
Figure E1: Flow East Case: LLG Fault on E4D @ Ear Falls
CAA ID 2010-420
51
August 16, 2011
Figure E2: Flow East Case: LLG Fault on E4D @ Dryden
CAA ID 2010-420
52
August 16, 2011
Figure E3: Flow East Case: LLG Fault on K23D @ Dryden
CAA ID 2010-420
53
August 16, 2011
Figure E4: Flow East Case: LLG Fault on D26A @ Dryden
CAA ID 2010-420
54
August 16, 2011
Figure E5: Flow East Case: LLG Fault on K3D @ Dryden
CAA ID 2010-420
55
August 16, 2011
Figure E6: Flow East Case: LLG Fault on M2D @ Dryden
CAA ID 2010-420
56
August 16, 2011
Figure E7: Flow East Case: LLG Fault on Dryden T23 @ Dryden 115 kV
CAA ID 2010-420
57
August 16, 2011
Figure E8: Flow West Case: LLG Fault on E4D @ Ear Falls 115 kV
CAA ID 2010-420
58
August 16, 2011
Figure E9: Flow West Case: LLG Fault on E4D @ Dryden 115 kV
CAA ID 2010-420
59
August 16, 2011
Figure E10: Flow West Case: LLG Fault on K23D@ Dryden 230 kV
CAA ID 2010-420
60
August 16, 2011
Figure E11: Flow West Case: LLG Fault on D26A@Dryden 230 kV
CAA ID 2010-420
61
August 16, 2011
Figure E12: Flow West Case: LLG Fault on K3D@Dryden 115 kV
CAA ID 2010-420
62
August 16, 2011
Figure E13: Flow West Case: LLG Fault on M2D@Dryden 230 kV
CAA ID 2010-420
63
August 16, 2011
Figure E14: Flow West Case: LLG Fault on Dryden T23@Dryden 115 kV
CAA ID 2010-420
64
August 16, 2011
Appendix F: Relay Margin Results
CAA ID 2010-420
65
August 16, 2011
M2D Moose Lake TS111
1.51E+00
M2D Dryden TS071986
Line Impedance
A21-P1-3PH Circle
A21P1 Circle
A21P2 Circle
A21-P2-3PH Circle
7.40E-01
A21P3 Circle
B21P1 Circle
Reactance
Reactance
9.10E-01
B21P2 Circle
3.10E-01
Margin_20%
-8.90E-01 -2.90E-01
-2.90E-01 3.10E-01
-8.90E-01
Line Impedance
A21P3-3PH Circle
B21B-P2-3PH
Circle
3.00E-02
-1.39E+00
9.10E-01 1.51E+00
-6.80E-01
3.00E-02
7.40E-01
-6.80E-01
Resistance
-1.39E+00
Resistance
Figure F1:Flow East: LLG fault on D26A @ Dryden - M2D Relay @ Moose Lake
Figure F2:Flow East: LLG fault on D26A @ Dryden - M2D Relay @ Dryden
M2D Moose Lake TS111
M2D Dryden TS071986
1.51E+00
Line Impedance
A21P1 Circle
Line Impedance
A21P2 Circle
A21-P1-3PH Circle
7.40E-01
A21P3 Circle
Reactance
Reactance
9.10E-01
B21P1 Circle
B21P2 Circle
3.10E-01
Margin_20%
-8.90E-01 -2.90E-01
-2.90E-01 3.10E-01
-8.90E-01
9.10E-01 1.51E+00
A21P3-3PH Circle
B21B-P2-3PH Circle
3.00E-02
-1.39E+00
-6.80E-01
3.00E-02
7.40E-01
Margin_20%
-6.80E-01
Resistance
-1.39E+00
Resistance
Figure F3: Flow East: LLG fault on D26A @ Mackenzie – M2D @ Moose Lake
CAA ID 2010-420
A21-P2-3PH Circle
66
Figure F4: Flow East: LLG fault on D26A @ Mackenzie – M2D @ Dryden
August 16, 2011
A22L Mackenzie TS1020
A22L Lakehead TS10200
Line Impedance
3.90E-01
Line Impedance
0.39
A21P2 Lens
A21P3 Circle
1.00E-02
-7.50E-01
-3.70E-01
1.00E-02
3.90E-01
B21P1 Circle
A21P1 Circle
Reactance
Reactance
A21P1 Circle
A21P2 Lens
A21P3 Circle
0.01
-0.75
-0.37
0.01
B21P1 Circle
0.39
B21P2 Mhol
-3.70E-01
B21P2 Mhol
-0.37
Margin_20%
Resistance
-7.50E-01
Resistance
-0.75
Figure F5: Flow East: LLG fault on AL21 @ Mackenzie - A22L Relay@ Mackenzie
Figure F6: Flow East: LLG fault on AL21 @ Mackenzie - A22L Relay@ Lakehead
B6M Birch TS022002
1
B6M Moose Lake TS022
A21P2B-3PH Circle
0
-0.5
0.5
1 B21P1 Circle
B21P2 Circle
Reactance
Reactance
A21P2A-2PH Circle
0.85
A21P2A-3PH Circle
-0.5
A21P1 Circle
1.42
A21P1 Circle
0
Line Impedance
1.99
Line Impedance
0.5
-1
margin_20%
A21P2A-3PH Circle
0.28
-1
-0.29
-0.43
A21P2B Circle
0.14
0.71
1.28
-0.86
Figure F7: Flow East: LLG fault on AL21 @ Mackenzie – B6M Relay@ Birch
CAA ID 2010-420
67
2.42
2.99
Margin_20%
-1.43
-2
B21P1 Circle
B21P2 Circle
Margin_20%
Resistance
-1
1.85
Resistance
Figure F8: Flow East: LLG fault on AL21 @ Mackenzie – B6M Relay@ Moose Lake
August 16, 2011
A22L Mackenzie TS1020
A22L Lakehead TS10200
3.90E-01
Line Impedance
Line Impedance
3.90E-01
A21P2 Lens
1.00E-02
-7.50E-01
-3.70E-01
1.00E-02
A21P3 Circle
3.90E-01
B21P1 Circle
A21P1 Circle
Reactance
Reactance
A21P1 Circle
A21P2 Lens
1.00E-02
A21P3 Circle
-7.50E-01 -3.70E-01 1.00E-02
B21P1 Circle
3.90E-01
B21P2 Mhol
-3.70E-01
B21P2 Mhol
-3.70E-01
Margin_20%
Resistance
-7.50E-01
Margin_20%
Resistance
-7.50E-01
Figure F10: Flow East: LLG Fault on A21L @ Lakehead – A22L Relay @ Mackenzie
B6M Birch TS022002
1.00E+00
Figure F11: Flow East: LLG Fault on A21L @ Lakehead – A22L Relay@
Lakehead
B6M Moose Lake TS022
Line Impedance
Line Impedance
1.51
A21P1 Circle
A21P1 Circle
A21P2A-2PH Circle
A21P2A-3PH Circle
0.94
B21P1 Circle
0.00E+00
-1.00E+00
-5.00E-01
0.00E+00
5.00E-01
1.00E+00
B21P2 Circle
A21P2B Circle
-5.00E-01
B21P2 Circle
Margin_20%
-0.77
Resistance
-1.00E+00
Figure F12: Flow East: LLG Fault on A21L @ Lakehead – B6M Relay @ Birch
68
B21P1 Circle
0.37
Margin_20%
CAA ID 2010-420
A21P2A-3PH Circle
A21P2B-3PH Circle
Reactance
Reactance
5.00E-01
-0.2
-0.2
0.37
-0.77
Resistance
0.94
1.51
Figure F13: Flow East: LLG Fault on A21L @ Lakehead – B6M Relay @ Moose
Lake
August 16, 2011
K3D Dryden TS051999
K3D Rabbit Lake SS02
1.50E+00
Line Impedance
1.00E+00
Line Impedance
A21P1-3PH Circle
A21P1 Circle
A21P2-3PH Circle
A21P2 Circle
9.10E-01
B21P1 Circle
Margin_20%
3.20E-01
-8.60E-01
3.20E-01
9.10E-01
B21P1 Circle
B21P2 Circle
Reactance
Reactance
B21P2 Circle
-8.60E-01 -2.70E-01
-2.70E-01
A21P3-3PH Circle
5.00E-01
Margin_20%
0.00E+00
-1.00E+00
1.50E+00
0.00E+00
1.00E+00
2.00E+00
-5.00E-01
Resistance
Resistance
-1.00E+00
Figure F14: Flow West: LLG Fault on K23D@ Kenora – K3D@ Rabbit Lake
Figure F15: Flow West: LLG Fault on K23D@ Kenora – K3D@ Dryden
K3D Rabbit Lake SS02
K3D Dryden TS051999
Line Impedance
1.50E+00
Line Impedance
1
A21P1 Circle
A21P1-3PH Circle
A21P2-3PH Circle
A21P2 Circle
A21P3-3PH Circle
B21P1 Circle
9.10E-01
0.5
B21P1 Circle
Margin_20%
3.20E-01
-8.60E-01 -2.70E-01
-2.70E-01
-8.60E-01
3.20E-01
9.10E-01
1.50E+00
B21P2 Circle
0
-1
-0.5
Margin_20%
0
0.5
1
1.5
2
-0.5
Resistance
-1
Figure F16: Flow West: LLG Fault on K23D @ Dryden – K3D@Rabbit Lake
CAA ID 2010-420
Reactance
Reactance
B21P2 Circle
69
Resistance
Figure F17: Flow West: LLG Fault on K23D @ Dryden – K3D@Dryden
August 16, 2011
Appendix G: Protection Impact Assessment
CAA ID 2010-420
70
August 16, 2011
PIA – Topping Turbogenerator Project
Revision: R0
Hydro One Networks Inc.
483 Bay Street
Toronto, Ontario
M5G 2P5
PROTECTION IMPACT ASSESSMENT
GREEN TRANSFORMATION PROGRAM – TOPPING TURBOGENERATOR
PROJECT
15.884 MVA TURBO GENERATOR
Date: April 19, 2011
P&C Planning Group Project #: PCT-217-PIA
Prepared by
Hydro One Networks Inc.
COPYRIGHT © HYDRO ONE NETWORKS INC. ALL RIGHTS RESERVED
PCT-217-PIA_Rev0_110419_SUMMARY.doc
Page 1 of 3
Revision: R0
Disclaimer
This Protection Impact Assessment has been prepared solely for the IESO for the purpose of assisting the IESO
in preparing the System Impact Assessment for the proposed connection of the proposed generation facility to
the IESO–controlled grid. This report has not been prepared for any other purpose and should not be used or
relied upon by any person, including the connection applicant, for any other purpose.
This Protection Impact Assessment was prepared based on information provided to the IESO and Hydro One by
the connection applicant in the application to request a connection assessment at the time the assessment was
carried out. It is intended to highlight significant impacts, if any, to affected transmission protections early in the
project development process. The results of this Protection Impact Assessment are also subject to change to
accommodate the requirements of the IESO and other regulatory or legal requirements. In addition, further
issues or concerns may be identified by Hydro One during the detailed design phase that may require changes
to equipment characteristics and/or configuration to ensure compliance with the Transmission System Code
legal requirements, and any applicable reliability standards, or to accommodate any changes to the IESOcontrolled grid that may have occurred in the meantime.
Hydro One shall not be liable to any third party, including the connection applicant, which uses the results of the
Protection Impact Assessment under any circumstances, whether any of the said liability, loss or damages
arises in contract, tort or otherwise.
Revision History
Revision
R0
Date
April 19, 2011
Change
Page 2 of 3
Revision: R0
EXECUTIVE SUMMARY
Figure 1: ~16 MVA Turbo Generation Connection to HONI Transmission System
It is feasible for Domtar Pulp and Paper Products to connect the proposed ~16 MVA steam generation at the
location in Figure 1.
PROTECTION HARDWARE
The present protections on D5D can accommodate the increase in generation and will continue to function with
the existing scheme for the Dryden TS terminal.
PROTECTION SETTING
The existing settings can cover the new scenario and require no change.
TELECOMMUNICATIONS
The existing telecommunication links can be retained to maintain the existing remote trip scheme.
DOMTAR DRYDEN RESPONSIBILITIES
The customer shall provide redundant distance protection scheme to cover faults on D5D (and on the alternate
supply M2D when supplied by M2D) and shall be responsible to reliably disconnect their equipment for a fault
on D5D (or M2D), even in case that a single contingency failure occurs in their P&C systems.
Page 3 of 3

Final Report - Ontario Power Authority

Transcription

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