: Correspondence 74 - OATI · PDF fileAPPENDIX C: MRO Study Case Single Line Diagram ... supplier does not supply the IEEE PSS2A. The PSS2B has a third lead/lag block which may be

Great Falls, McArthur Falls and Slave Falls Generator Uprate and Excitation and Governor Systems Upgrade Interconnection Evaluation Study

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Table of Contents

Table of Contents ........................................................................................... 2 1. Executive Summary ................................................................................. 4 2. Recommendations .................................................................................... 7

2.1 Recommendations for Great Falls G.S. Generator Re- runner and Re-wind ...................................................................................................................... 7

2.2 Recommendations for Great Falls G.S. Generator Excitation Systems ....... 7 2.3 Recommendations for McArthur Falls G.S. Excitation Systems ................... 9 2.4 Recommendations for Slave Falls G.S. Generator Re-runner and Re-wind

.................................................................................................................... 11 2.5 Recommendations for Slave Falls G.S. Excitation Systems ...................... 11 2.6 Recommendations for Great Falls G.S., McArthur Falls G.S. and Slave

Falls G.S. Proposed Digital Speed Governors ............................................ 13 2.7 Recommendations for Great Falls G.S., McArthur Falls G.S. and Slave

Falls G.S. Mathematical Computer Models ................................................. 14 3. Introduction ............................................................................................... 14

3.1 Considerations at Great Falls G.S. ............................................................ 15 3.2 Considerations at McArthur Falls G.S. ....................................................... 15 3.3 Considerations at Slave Falls G.S. ............................................................ 15 3.4 Deliverables ............................................................................................... 16

4. Base Case Study Models ...................................................................... 16 5. Short Circuit Analysis ............................................................................ 17 6. ACCC Analysis ......................................................................................... 17 7. Transient Stability Analysis ................................................................. 19

7.1 Great Falls Units 1, 2, 4, 5, and 6 Exciter Upgrades .................................. 19 7.2 McArthur Falls Units 1 to 8 Exciter Upgrades ........................................... 24 7.3 Slave Falls Units 1 to 8 Exciter Upgrades .................................................. 28

8. Small Signal Stability Studies ............................................................. 31 9. Governor Replacement Considerations .......................................... 38 10. Stability Model Requirements .......................................................... 41

10.1 Stability Model Requirements for Governors............................................ 41 10.2 Stability Model Requirements for Excitation System Controls.................. 43


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11. References .............................................................................................. 44 APPENDIX A : Interconnection Evaluation Study Agreements .......................... 46 APPENDIX B: Correspondence .......................................................................... 74 APPENDIX C : MRO Study Case Single Line Diagram ...................................... 77


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1. Executive Summary

This Interconnection Evaluation Study (IES) report summarizes a joint Winnipeg River study which addresses separate interconnection requests from the Generation Maintenance Engineering Department, Generation South, for proposed generator uprate along with substantial modifications to the excitation systems and speed governing systems at Great Falls G.S., McArthur Falls G.S. and Slave Falls G.S.. As the system effects of upgrades at any one location could impact the proposed upgrades at the others it was decided that a joint Winnipeg River study was necessary. Specifically the joint IES study addresses the following: 1. Great Falls G.S.: The impact of 3 MW of additional generation above

the original 8 MW increase in generation approved based on a previous Interconnection Facility Study (IFS) report issued in July 2003 [1]. Also the replacement of existing Automatic Voltage Regulators (AVRs) and rotating main exciters with full static exciters and existing electro-mechanical governors with digital governors on the remaining 5 units. The projected In-Service Date is 2009.

2. McArthur Falls G.S.: The impact of replacing existing AVRs and

rotating main exciters with full static exciters or replacing only the AVRs with static pilot exciters on all eight units. The projected In-Service Date is 2011.

3. Slave Falls G.S.: The impact of an additional 28 MW of generation

increase along with the replacement of existing AVRs and rotating main exciters with full static exciters and the replacement of existing electro-mechanical governors with digital governors on all eight units. The projected In-Service Date is 2009.

The IES makes the following conclusions: 1. There are no detrimental effects to the Manitoba Hydro power system if

Power Supply replaces existing AVRs and rotating main exciters at Great Falls units 1,2,4,5,and 6, McArthur Falls units 1 to 8 and Slave Falls units 1 to 8 with full high initial response static exciters.

2. The installation of high initial response static exciters provides some

improvement to the transient stability of the power system in the vicinity of these stations following system faults in the area.

3. The installation of high initial response exciters excites local oscillatory

modes but this can be addressed relatively inexpensively with the


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inclusion of Power System Stabilizers (PSSs) as part of the excitation system package.

4. The proposed replacement of existing electromechanical governors

with digital governors may provide better dynamic response of the units following load rejections. However this does not significantly impact the overall operation of the power system. This benefit would be more evident if part or the whole Manitoba Hydro system becomes isolated.

5. AC Contingency Calculations (ACCC) analysis shows that in terms of

line ratings and voltage violations, the proposed re-runnering and re-winding of units at Great Falls G.S. and Slave Falls G.S. to increase output by 3 MW and 28 MW, respectively, will result in no major upgrades to the power system but minor upgrades may be required. ACCC violations will be screened more closely at the IFS stage and any necessary facility upgrades will be determined. If facility upgrades are required then cost estimates will be prepared.

6. Considering existing fault levels at Great Falls and Slave Falls and the

recent replacement of all 115 kV breakers with ones having significantly higher maximum short circuit interrupting ratings, the increase in MW output at these two stations is not expected to pose any concern.

The IES makes the following recommendations: 1. Existing AVRs and rotating main exciters shall be replaced by full high

initial response static exciters on all units at McArthur Falls G.S. and Slave Falls G.S.. Due to the age and vintage of existing rotating main exciters at these two stations, and the potential impact of power system stabilizers at these locations, static pilot exciters which provide voltage regulation via existing rotating main exciters, are not recommended for these two stations.

2. Existing AVRs and rotating main exciters shall be replaced by full high

initial response static exciters on the remaining units (1,2,4-6) at Great Falls G.S.. These exciters shall be of similar functionality to the existing exciter on Great Falls Unit 3 which was commissioned in August 2003.

3. The new high initial response exciters shall come equipped with

modern dual input power system stabilizers along with line drop compensators.

4. Excitation system limiters included in the excitation system package

shall operate to limit and not trip the machine.


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5. New digital governors to replace the existing electro-mechanical governors on all units at Great Falls, McArthur Falls and Slave Falls shall be based on the functionality requirements presented in this report.

6. Suppliers shall provide both detailed as well as standard IEEE

mathematical computer study models of all excitation systems and speed governor controls, which are compatible with MRO and NERC requirements, as outlined in this report.

7. Should this project proceed to the Interconnection Facility Study (IFS)

stage, additional short circuit and ACCC studies shall be performed to determine anticipated short circuit levels in the area and the requirement for facility upgrades. IFS shall provide for closer screening of ACCC violations and cost estimates shall be prepared for any necessary facility upgrades.

As per the IES agreements, all funding for the substantial modifications at Great Falls, McArthur Falls and Slave Falls shall come from the Power Supply Division.


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2. Recommendations The recommendations from this IES are provided below for each station studied as per the IES agreements. As per the IES agreements, all funding for the substantial modifications at Great Falls, McArthur Falls and Slave Falls shall be come from the Power Supply Division.

2.1 Recommendations for Great Falls G.S. Generator Re- runner and Re-wind

The impact of 3 MW of additional generation above the original 8 MW increase may proceed without any major negative impact to the power system from a steady state or stability perspective. Should this project proceed to the Interconnection Facility Study (IFS) stage, additional short circuit and ACCC studies shall be performed to determine anticipated short circuit levels in the area and the requirement for facility upgrades. The IFS shall provide for closer screening of ACCC violations and cost estimates shall be prepared for any necessary facility upgrades.

2.2 Recommendations for Great Falls G.S. Generator Excitation Systems

Based on the results and discussions above and work already performed on Great Falls Unit 3, the following are recommended for Great Falls Units 1,2,4,5 and 6 excitation system upgrades:

Fast, bus fed, high initial response full static exciters with continuous

acting voltage regulators; the exciters will be required to circulate positive field current only;

The time for the excitation voltage to reach 95% of the difference

between ceiling voltage and rated load field voltage shall be 25 milliseconds or less after a sudden sustained 5% step change in generator terminal voltage;

Exciter field forcing voltage limits Efdmax and Efdmin shall be specified

as +6.0 pu and –5.0 pu, respectively. In this case, 1 pu field voltage shall be defined as the generator field voltage required to produce 1 pu terminal (stator) voltage on the open circuit air-gap line. Rotor insulation shall be specified to accommodate these limits.


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The exciter voltage regulator shall be specified to include Line Drop Compensation (LDC). The available LDC shall range from zero to a minimum of 60% of step-up transformer impedance.

Excitation system limiters included in the excitation system package

shall operate to limit and not trip the machine. A standard IEEE PSS2A power system stabilizer, to be part of the

excitation system package. An IEEE PSS2B PSS is acceptable if there are small or no cost differences between the two and/or if the supplier does not supply the IEEE PSS2A. The PSS2B has a third lead/lag block which may be bypassed. Parameter ranges and study parameters for the PSS are shown below.

Great Falls U 1,2,4,5,6 Recommended PSS Parameter Ranges and

Study Values

Parameter Description Simulation Value Great Falls U1,2,4,5,6

Recommended Parameter Range

Tw1 First washout time constant in speed path

2.0 sec. 0.3010.0 Tw sec.

Tw2 Second washout time constant in speed path

2.0 sec. 0.3020.0 Tw sec.

T6 Signal transducer time constant in speed path

0.02 sec. .0.1060.0 T sec.

Tw3 First washout time constant in power path

2.0 sec. 0.3030.0 Tw sec.

Tw4 Second washout time constant in Power path

0.0 sec. (Block Bypassed in

PSS/E)

0.3040.0 Tw sec. ( Set Tw4 High (30.0 sec.) if block cannot be bypassed )

T7 Signal transducer time constant in Power path

2.0 sec. 0.3070.0 T sec.

Ks2 Signal transducer gain in Power path

0.402

HTw

21

0.520.0 Ks

Ks3 Integral of Electric Power gain 1.0 0.130.0 Ks

T8 Ramp tracking filter lead time constant

0.03 sec. 0.381.0 T sec.

T9 Ramp tracking filter lag time constant

0.012 sec. 0.1902.0 T sec.

Ks1 Stabilizer gain 6.0 0.5010.0 Ks

T1 First lead/lag lead time constant

0.18 sec. 0.510.0 T sec.

T2 First lead/lag lag time constant 0.11 sec. 0.520.0 T sec.

T3 Second lead/lag lead time constant

0.11 sec. 0.530.0 T sec.

T4 Second lead/lag lag time constant

0.04 sec. 0.540.0 T sec.

T10 Third lead/lag lead time constant (may be provided by

manufacturer)

1.0 sec. 0.5100.0 T sec.

T11 Third lead/lag lag time constant (may be provided by

manufacturer)

1.0 sec. 0.5110.0 T sec.

M Ramp tracking filter lag function index

5 101 M


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Parameter Description Simulation Value Great Falls U1,2,4,5,6


N Ramp tracking filter overall index

1 21 N

Vpssmax Stabilizer output maximum limit 0.05 pu 2.00 max Vpss

Vpssmin Stabilizer output minimum limit -0.05 pu 0.02.0 min Vpss

2.3 Recommendations for McArthur Falls G.S. Excitation Systems

The following are recommended for the proposed excitation system upgrades on McArthur Falls Units 1-8: Fast, bus fed, high initial response full static exciters with continuous


Due to the age and vintage of existing rotating main exciters at this

station, and the potential impact of power system stabilizers, static pilot exciters which provide voltage regulation via existing rotating main exciters, are not recommended.




as +6.0 pu and –5.0 pu, respectively. In this case, 1 pu field voltage shall be defined as the generator field voltage required to produce 1 pu terminal (stator) voltage on the open circuit air-gap line. If the rotors of these units are not sufficiently insulated to accommodate these limits then the highest field forcing limits allowable shall be used.

The exciter voltage regulator shall be specified to include Line Drop

Compensation (LDC). The available LDC shall range from zero to a minimum of 60% of step-up transformer impedance.



A standard IEEE PSS2A power system stabilizer, to be part of the excitation system package. An IEEE PSS2B PSS is acceptable if there are small or no cost differences between the two and/or if the supplier does not supply the IEEE PSS2A. The PSS2B has a third


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lead/lag block which may be bypassed. Parameter ranges and study parameters for the PSS are shown below.

McArthur Falls U1-8 Recommended PSS Parameter Ranges

and Study Values

Parameter Description Simulation Value

McArthur Falls U1-8



2.0 sec. 0.3010.0 Tw sec.


2.0 sec. 0.3020.0 Tw sec.


0.02 sec. .0.1060.0 T sec.


2.0 sec. 0.3030.0 Tw sec.


0.0 sec. (Block Bypassed

in PSS/E)

0.3040.0 Tw sec.

( Set Tw4 High (30.0 sec.) if block

cannot be bypassed ) T7 Signal transducer time constant in

Power path 2.0 sec. 0.3070.0 T

sec.

Ks2 Signal transducer gain in Power path

0.5814

HTw

21

0.520.0 Ks



0.03 sec. 0.381.0 T sec.


0.012 sec. 0.1902.0 T sec.


T1 First lead/lag lead time constant 0.18 sec. 0.510.0 T sec.


T3 Second lead/lag lead time constant 0.11 sec. 0.530.0 T sec.

T4 Second lead/lag lag time constant 0.04 sec. 0.540.0 T sec.

T10 Third lead/lag lead time constant (may be provided by manufacturer)

1.0 sec. 0.5100.0 T sec.

T11 Third lead/lag lag time constant (may be provided by manufacturer)

1.0 sec. 0.5110.0 T sec.


5 101 M

N Ramp tracking filter overall index 1 21 N


Vpssmin Stabilizer output minimum limit -0.05 pu 02.0 min Vpss


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2.4 Recommendations for Slave Falls G.S. Generator Re-runner and Re-wind

Based on ACCC, short circuit and transient stability analysis completed in this IES, the planned re-runnering and re-winding of the 8 generators at the Slave Falls G.S. to obtain an additional 28 MW from the plant can proceed without any major impact to the Manitoba Hydro power system. Should this project proceed to the Interconnection Facility Study (IFS) stage, additional short circuit and ACCC studies shall be performed to determine anticipated short circuit levels in the area and the requirement for facility upgrades. The IFS shall provide for closer screening of ACCC violations and cost estimates shall be prepared for any necessary facility upgrades.

2.5 Recommendations for Slave Falls G.S. Excitation Systems

The following are recommended for the proposed excitation system upgrades on Slave Falls Units 1-8:

Fast, bus fed, high initial response static exciters with continuous


Due to the age and vintage of existing rotating main exciters at this

station, and the potential impact of power system stabilizers, static pilot exciters which provide voltage regulation via existing rotating main exciters, are not recommended.




as +6.0 pu and –5.0 pu, respectively. In this case, 1 pu field voltage shall be defined as the generator field voltage required to produce 1 pu terminal (stator) voltage on the open circuit air-gap line. Rotor insulation shall be specified to accommodate these limits.


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A standard IEEE PSS2A power system stabilizer, to be part of the excitation system package. An IEEE PSS2B PSS is acceptable if there are small or no cost differences between the two and/or if the supplier does not supply the IEEE PSS2A. The PSS2B has a third lead/lag block which may be bypassed. Parameter ranges and study parameters for the PSS are shown below.

Slave Falls U1-8 Recommended PSS Parameter Ranges and Study

Values

Parameter Description Simulation Value Slave Falls U1-8



2.0 sec. 0.3010.0 Tw sec.


2.0 sec. 0.3020.0 Tw sec.


0.02 sec. .0.1060.0 T sec.


2.0 sec. 0.3030.0 Tw sec.



PSS/E)

0.3040.0 Tw sec.

( Set Tw4 High (30.0 sec.) if block cannot be bypassed

) T7 Signal transducer time constant

in Power path 2.0 sec. 0.3070.0 T

sec. Ks2 Signal transducer gain in Power

path 0.3215

HTw

21

0.520.0 Ks



0.03 sec. 0.381.0 T sec.


0.012 sec. 0.1902.0 T sec.



0.18 sec. 0.510.0 T sec.



0.11 sec. 0.530.0 T sec.


0.04 sec. 0.540.0 T sec.

T10 Third lead/lag lead time constant (may be provided by

manufacturer)

1.0 sec. 0.5100.0 T sec.


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T11 Third lead/lag lag time constant (may be provided by

manufacturer)

1.0 sec. 0.5110.0 T sec.


5 101 M


1 21 N


Vpssmin Stabilizer output minimum limit -0.05 pu 0.02.0 min Vpss

2.6 Recommendations for Great Falls G.S., McArthur Falls G.S. and Slave Falls G.S. Proposed Digital Speed Governors

Different suppliers provide different forms of speed governing systems. It is therefore recommended that general governor functionality be provided to governor suppliers for the three plants under consideration. The specification for Digital governors should be as broad as possible. Standard governor requirements are provided in the ANSI/IEEE Standard 125-2005, “IEEE Recommended Practice for Preparation of Equipment Specifications for Speed-Governing of Hydraulic Turbines Intended to Drive Electric Generators”. Some of the functional requirements provided here will be based on the IEEE guide as well as those developed for Wuskwatim [7]. Based on the above it is recommended that governors be specified according to the parameter ranges shown in the table below. General Governor Specifications for Great Falls, McArthur Falls and Slave Falls

Parameter Suggested Range Study Value

Permanent Droop/Speed Regulation

Adjustable from 0 to 10% in steps of 1%

4%

Dead Band Should not exceed 0.036 Hz 0.0 Dead Time For step load change of more than

10% of capacity of turbine, dead time shall not exceed 0.2 seconds

0.0 sec.

Temporary Speed Droop Time Constant

This parameter shall be continuously adjustable from 0 to 30 seconds.

6.1 sec.

Temporary Speed Droop

Shall be continuously adjustable from 0 to 150 %.

36.0 %

Proportional Gain Shall be continuously adjustable from 0 to 20

1.0 pu

Derivative Gain Shall be continuously adjustable from 0 to 5 seconds

0.0 sec.


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Integral Gain Shall be continuously adjustable from 0 to 10 per second

0.0 sec-

1

2.7 Recommendations for Great Falls G.S., McArthur Falls G.S. and Slave Falls G.S. Mathematical Computer Models

For modeling purposes it is recommended that the supplier(s) of excitation

system and speed governor controls provide Manitoba Hydro with detailed as well as standard IEEE models of their equipment. These models shall be used for loadflow and stability planning and operating studies and shall be compatible with PSS/E version 29 and later and PSCAD/EMTDC V 4.2.1 or later. Models shall satisfy all requirements regarding verification as stipulated by the MRO and NERC. It is further recommended that all powerflow and stability models along with manufacturer testing of these, satisfy the detailed requirements presented in Section 10 of this IES report.

3. Introduction

According to the terms and conditions of the Manitoba Hydro Open Access Interconnection Tariff, the Manitoba Hydro Power Supply Business Unit, referred to as The Generator, submitted three separate interconnection requests for Manitoba Hydro to prepare Interconnection Evaluation Study (IES) reports. The Generator requested that Manitoba Hydro assess the impact on steady-state, transient and small signal stability of the power system as well as short circuit levels, due to the proposed generator uprating and substantial modifications to excitation systems and to governor systems at Great Falls G.S., McArthur Falls G.S. and Slave Falls G.S..

Details on the substantial modifications proposed for the three plants can be found in the attached Interconnection Evaluation Study Agreements in Appendix A. Brief summaries, as they apply to each plant, are provided below. As the system effects of substantial modifications at any one location could impact proposed upgrades and generator control parameter recommendations at others, including plants in the vicinity which are not included in the upgrade projects, it was decided that a joint Winnipeg River study was necessary.


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3.1 Considerations at Great Falls G.S.

Great Falls G.S. is located on the Winnipeg River and currently has six units with an overall plant rating of 151.3 MVA. As part of the Great Falls Unit 3 and 4 re-runnering projects, Great Falls Unit 3 was re-runnered, rewound and equipped with a new full static exciter, complete with a dual input power system stabilizer and commissioned in August 2003, see references [2, 3, 4, and 5] for details. The additional generation approved for this project, based on the IFS report of July 14, 2003 [1] was 8 MW.

This IES will evaluate the impact of the generation increase of an additional 3 MW of Network Resource Interconnection Service. The additional 3 MW of generation output at Great Falls exceeds the approved facility generation level of 139.6 MW of Network Resource Interconnection service associated with the Unit 3 and 4 re-runnering project.

This IES will also consider the replacement of existing Automatic Voltage Regulators (AVRs) and rotating main exciters with full static exciters and existing electro-mechanical governors with digital governors on the remaining 5 units. The projected in-service date is 2009.

3.2 Considerations at McArthur Falls G.S.

McArthur Falls G.S. in located on the Winnipeg River and currently has eight units with an overall plant rating of 68 MVA. The IES will evaluate the impact of replacing existing rotating main exciters and AVRs on each unit with either full static exciters or static pilot exciters. If full static exciters are recommended the AVR as well as the rotating main exciter on each unit will be replaced with a full static exciter. Should static pilot exciters be recommended, these will replace the AVR on each unit and will provide regulation of the generator field voltage through the existing main exciter.

The IES will also evaluate the impact of replacing existing electro-

mechanical governors on each of the eight units with digital governors. The projected in-service date is 2011.

3.3 Considerations at Slave Falls G.S.

Slave Falls G.S. is located on the Winnipeg River and currently has eight units with an overall plant rating of 80 MVA (72 MW @ 0.9 pf lagging). The IES will evaluate the impact of re-runnering and re-winding these units in order to obtain an additional 28 MW of additional generation at this location.

The IES will also evaluate the impact of substantial modifications to the

excitation systems and speed governors associated with these units. The proposed work involves replacing existing rotating main exciters and AVRs on each unit with either full static exciters or static pilot exciters. If full static


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exciters are recommended the AVR as well as the rotating main exciter on each unit will be replaced with a full static exciter. Should static pilot exciters be recommended, these will replace the AVR on each unit and will provide regulation of the generator field voltage through the existing main exciter.

The IES will also evaluate the impact of replacing existing electro-

mechanical governors on each of the eight units with digital governors. The projected in-service date is 2009.

3.4 Deliverables

This joint IES will consider the steady-state, transient and small signal stability effects along with impacts on fault levels in the area due to the generation increase along with proposed substantial modifications to existing excitation and speed governing systems at these three plants. The study will evaluate the impact on the Manitoba Hydro system as well as the surrounding interconnected power system. Short Circuit Analysis is required to assess any increased short circuit levels on proposed new breaker layout and proposed increased generator output at Great Falls and Slave Falls. Studies will be conducted under several simulated system scenarios, generator loading and seasonal conditions.

The deliverables from the study will include conclusions and recommendations pertaining to the procurement of generator protection and control equipment, equipment ratings, control parameters design ranges along with settings used in the study.

4. Base Case Study Models

This study was performed using a 2005 UIP stability package with control upgrades and loadflow cases projected to consider present system loading as well as projected 2009 and 2014 summer peak and winter peak loading conditions. These study cases were used to evaluate steady state, AC contingency (ACCC) and transient stability impacts using the PSS/E loadflow and stability simulation tools. Eigenvalue, frequency domain analysis for evaluating small signal stability impacts utilized converted versions of these cases with more detailed modeling of the Manitoba Hydro HVdc system included. Eigenvalue analysis was performed using the Small Signal Analysis Tool (SSAT).


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In performing these studies consideration was given to generators higher in the queue which may impact the results of this study and affect its conclusions and recommendations. The following assumptions were made:

- The northern ac group of generators in the queue, that is, the firming of Kelsey, Kettle on ac, Jenpeg and Wuskwatim will not impact the results of this study and therefore were not considered.

- The proposed 300 MW wind plant was not included in this study based on anticipated minimal impact to the study results.

- The new plant at Pointe du Bois may have some impact on the study

results but because the final transmission plan was unknown at the time of this study none was assumed. This will require further analysis at the IFS stage.

- The IFS will also cover the full range of firm import/export capability.

5. Short Circuit Analysis

Based on information obtained from Transmission Network Planning, System Planning Department (see Appendix B), the 115 kV circuit breakers in the Winnipeg River 115 kV system where Great Falls and Slave Falls are located were recently replaced with new breakers and the 115 kV bus arrangements modified. Existing 115 kV bus fault levels at Great Falls are in the order of 10 - 11 kA and at Slave Falls in the order of 4-5 kA.

The new 115 kV breakers which were installed in the 115 kV Winnipeg River power system have a minimum of around 40 - 50 kA maximum short circuit interrupting rating. The 3 MW generation increase at Great Falls and 28 MW generation increase at Slave Falls is expected to have minimal effects on the short circuit levels and hence will not affect circuit breaker requirements.

Should this project proceed to the IFS stage, Transmission Network Planning recommends that additional studies be performed at that time to determine the impact of the modifications on fault levels in the area.

6. ACCC Analysis

In order to evaluate the proposed facility upgrades at Great Falls, McArthur Falls and Slave Falls generating stations, load flow analysis which included single and multi-element contingencies were performed using the AC Contingency Calculation (ACCC) in PSS/E. AC single contingency analysis,


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similar to that which was performed for facility upgrades at Pine Falls G.S. (see reference [6]), was performed here.

The objective of the ACCC analysis is to identify any transmission limitations where changes will cause line rating or voltage violations within the loadflows following a single contingency outage. Common tower contingency outages, where two separate circuits share the same tower, were also included. Screening parameters for the ACCC analysis was set at 0.01 pu voltage change and 2% flow change.

Due to time constraints, the ACCC analysis was limited to futuristic, high loading, high generation and high power transfer system conditions with the Manitoba Hydro power system operating highly stressed. A modified 2014 winter peak case which included increased generation at Pine Falls, Great Falls and Slave Falls was used in this analysis. Some results from the ACCC line flow analysis report are shown in Table 1 below.

Table 1: ACCC Contingency Analysis Flow Report

Some results from the ACCC monitored voltage report is shown below in Table 2.

Table 2: Results from ACCC Monitored Voltage Report

ACCC OVERLOAD REPORT: MONITORED ELEMENTS LOADED ABOVE 100.0 % OF RATING SET C

DISTRIBUTION FACTOR FILE: ../accc/i01-wp14aa.7N00YXW_mod_GF7_SF28.dfx

MONITORED ELEMENT CONTINGENCY RATE FLOW %67504 KELSEY 6 138 67689*KLSY1-7G13.8 1 BASE CASE 298.0 305.4 102.567504 KELSEY 6 138 67689*KLSY1-7G13.8 1 SINGLE 1293 298.0 305.1 102.167551 ROVER 863.5 67653*CHARLES863.5 1 SINGLE 1418 44.0 46.13 104.867551 ROVER 863.5 67653*CHARLES863.5 1 SINGLE 1419 44.0 46.13 104.867541 STVITAL7 110 67620*SCOTLDB7 110 1 SINGLE 1467 143.7 146.6 102.067552 POINTDB863.5 67698*PDB5-16G6.90 1 SINGLE 1472 30.0 31.1 103.667552 POINTDB863.5 67698*PDB5-16G6.90 1 SINGLE 2208 30.0 31.1 103.6

ACCC OVERLOAD REPORT: MONITORED ELEMENTS LOADED ABOVE 100.0 % OF RATING SET C

DISTRIBUTION FACTOR FILE: ../accc/i01-wp14aa.7N00YXW_mod_GF7_SF28.dfx

MONITORED ELEMENT CONTINGENCY RATE FLOW %67504 KELSEY 6 138 67689*KLSY1-7G13.8 1 BASE CASE 298.0 305.4 102.567504 KELSEY 6 138 67689*KLSY1-7G13.8 1 SINGLE 1293 298.0 305.1 102.167551 ROVER 863.5 67653*CHARLES863.5 1 SINGLE 1418 44.0 46.13 104.867551 ROVER 863.5 67653*CHARLES863.5 1 SINGLE 1419 44.0 46.13 104.867541 STVITAL7 110 67620*SCOTLDB7 110 1 SINGLE 1467 143.7 146.6 102.067552 POINTDB863.5 67698*PDB5-16G6.90 1 SINGLE 1472 30.0 31.1 103.667552 POINTDB863.5 67698*PDB5-16G6.90 1 SINGLE 2208 30.0 31.1 103.6

MONITORED VOLTAGE REPORTSYSTEM CONTINGENCY BUS V-CONT V-INIT V-MAX V-MIN'MAPP ' RANGE SINGLE 1313 67597 DORSY2T946.0 1.1151 1.0735 1.1000 0.9000'MAPP ' RANGE SINGLE 1421 67580 SHERBK 7 110 0.8905 1.0167 1.1000 0.9000'MAPP ' RANGE SINGLE 1421 67755 SHBK-PH7 110 0.8905 0.9968 1.1000 0.9000'MAPP ' RANGE SINGLE 1472 67552 POINTDB863.5 1.1040 1.1184 1.1000 0.9000'MAPP ' RANGE SINGLE 1473 67552 POINTDB863.5 1.1381 1.1184 1.1000 0.9000'MAPP ' RANGE SINGLE 1473 67553 POINTDB7 110 1 1313 1 1050 1 1000 0 9000

MONITORED VOLTAGE REPORTSYSTEM CONTINGENCY BUS V-CONT V-INIT V-MAX V-MIN'MAPP ' RANGE SINGLE 1313 67597 DORSY2T946.0 1.1151 1.0735 1.1000 0.9000'MAPP ' RANGE SINGLE 1421 67580 SHERBK 7 110 0.8905 1.0167 1.1000 0.9000'MAPP ' RANGE SINGLE 1421 67755 SHBK-PH7 110 0.8905 0.9968 1.1000 0.9000'MAPP ' RANGE SINGLE 1472 67552 POINTDB863.5 1.1040 1.1184 1.1000 0.9000'MAPP ' RANGE SINGLE 1473 67552 POINTDB863.5 1.1381 1.1184 1.1000 0.9000'MAPP ' RANGE SINGLE 1473 67553 POINTDB7 110 1 1313 1 1050 1 1000 0 9000


Page 19

Results from the ACCC analysis show no major violations in flow and voltage of concern in the area due to the contingency analysis. As seen in both Tables 1 and 2, some values were marginal in the stressed case prior to the contingency analysis. Therefore the proposed uprating of Great Falls units 1,2,4,5 and 6 to obtain an additional 3 MW above the 8 MW already approved, will not have any significant negative impact on the power system and may go forward. Similarly, based on ACCC results, the proposed 28 MW uprating of the Slave Falls units may also proceed. Should this project proceed to the IFS stage, further ACCC analysis is recommended.

7. Transient Stability Analysis

This section of the study was completed in order to evaluate the impact of the proposed substantial modifications to the excitation systems and speed governor controls for the Great Falls, McArthur Falls and Slave Falls generating stations. In the following sections the impact of these proposed changes on the stations themselves as well as the surrounding power system will be evaluated separately for each station.

7.1 Great Falls Units 1, 2, 4, 5, and 6 Exciter Upgrades For these studies Great Falls Units 1, 2, 4, 5 and 6 are netted and modelled as one generator, similar to what was done in references [1], [2],and [5]. Simulations were conducted with existing exciter models on this unit representing the existing arrangement of an AVR regulating a rotating main exciter which is used to regulate the field voltage of the unit. To represent the


Page 20

proposed fast, high initial response full static exciters, models similar to those of the refurbished Great Falls Unit 3 was used (see reference [5]). The Power System Stabilizer transfer function for Unit 3 was also modeled on the netted unit to represent future dual input PSS2A or PSS2B type PSSs on each unit. Figure 1 shows the rotor angle of the generator which represents Units 1,2,4,5 and 6 following a three phase, five cycle fault on the Great Falls 115 kV bus (see single line diagram in Appendix C). A 3-5 cycle fault clearing time is typical for faults in the Manitoba Hydro’s 115 kV system. Figure 2 shows a “zoomed in” version of the same waveform. Results show that the proposed faster full static exciter will significantly increase the speed of response of the unit to voltage changes and improve the steady state voltage regulation. Results also demonstrate that the transient response of the units at Great Falls will also improve following a close-in bus fault, by lowering the “first swing” transient rotor angle deviation. Typically the speed of response of a high speed exciter also serves as a detriment by exciting local oscillatory modes [7, 8]. The results show that the response of the two types of exciters, from a damping perspective is practically identical. Adding a PSS, identical to that on Unit 3, will significantly improve the damping provided to the local mode. Studies to date have not identified a need for Great Falls units to provide damping to inter-area modes of oscillation. Based on the relative low cost of adding a PSS to the proposed fast excitation system, it is recommended that a PSS be added to each unit at Great Falls. Reference [2] shows the overall benefits of having PSSs installed on all six units at Great Falls G.S. In reference [5] the addition of a line drop compensator to Great Falls Unit 3 was discussed in detail as well as the future benefits of having line drop compensators installed on all six units at Great Falls. Results showed small improvements in the voltage recovery levels on the Great Falls 115 kV bus following disturbances in the vicinity of the station when line drop compensation was modeled on Unit 3.

Figure 1 Rotor angles of Great Falls Units 1,2,4,5 & 6 with fast and existing exciters for a 3 ph., 5 cy. Fault on great Falls 115 kV bus.


Page 21

Figure 1: Great Falls Units 1,2,4,5 & 6 response to a 5 cy., 3 ph. Fault on Great Falls 115 kV Bus with Existing and Proposed Exciters


Page 22

Figure 2: “Zoomed in” version of Figure 1

Figure 3: Great Falls Bus Voltage with LDC modelled on U3

Figure 4: 60% LDC on all units at Great Falls

Gr e a t Fa lls Bus Volta ge Following Tr ip of Line GT1

for Va r ious % of LDC on U3

1.09751.098

1.09851.099

1.09951.1

1.10051.101

1.10151.102

1.1025

0 0.2 0.4 0.6 0.8 1 1.2 1.4 1.6 1.8 2Tim e in se conds

Vo

lta

ge

in

pu

U3 LDC @ 0% U3 LDC @ 30% U3 LDC @ 60%

Gr e a t Fa lls Bus Volta ge Following Tr ip of Line s GT1 & GS2 2 for 0 & 6 0 % LDC on Units 1 - 6

1.085

1.09

1.095

1.1

1.105

1.11

1.115

1.12

0 0.2 0.4 0.6 0.8 1 1.2 1.4 1.6 1.8 2

Tim e in se conds

Vo

lta

ge

in

pu

Grt. Falls. Bus Vlt. (no LDC) Grt. Falls. Bus Vlt. (60% LDC on all units)


Page 23

Significant improvements were observed when line drop compensation was modeled on all six generators at Great Falls. Figures 3 and 4 demonstrate the benefits of installing line drop compensation on all units at Great Falls. Figures 3 shows the Great Falls 115 kV bus voltage following a trip of line GT1 (Great Falls to Lac Du Bonnet) with 0 %, 30 % and 60 % LDC modelled on the refurbished Unit 3. Figure 4 show the response of the Great Falls units to a similar disturbance with 60% LDC modeled on all six Great Falls units. Typically between 50% and 80% of the transformer impedance is compensated using the line drop compensator. At Manitoba Hydro, line drop compensation is normally limited to around 60% of transformer impedance. Based on the results and discussions above and work already performed on Great Falls Unit 3, the following are recommended for Great Falls units 1,2,4,5 and 6 excitation system upgrades:

Fast, bus fed, high initial response static exciters with continuous acting

voltage regulators; the exciters will be required to circulate positive field current only;



Exciter field forcing voltage limits Efdmax and Efdmin shall be specified as

+6.0 pu and –5.0 pu, respectively. In this case, 1 pu field voltage shall be defined as the generator field voltage required to produce 1 pu terminal (stator) voltage on the open circuit air-gap line. Rotor insulation shall be specified to accommodate these limits.





excitation system package. An IEEE PSS2B PSS is acceptable if there are small or no cost differences between the two and/or if the supplier does not supply the IEEE PSS2A. The PSS2B has a third lead/lag block which may be bypassed. Parameter ranges and study parameters for the PSS are shown in Table 3 below.

Table 3: Great Falls U 1,2,4,5,6 Recommended PSS Parameter Ranges and Study Values


Page 24


Great Falls U1,2,4,5,6 Recommended

Parameter Range Tw1 First washout time

constant in speed path 2.0 sec. 0.3010.0 Tw

sec. Tw2 Second washout time


sec. T6 Signal transducer time

constant in speed path 0.02 sec. .0.1060.0 T

sec. Tw3 First washout time

constant in power path 2.0 sec. 0.3030.0 Tw


constant in Power path


PSS/E)

0.3040.0 Tw sec.

( Set Tw4 High (30.0 sec.) if block cannot be

bypassed ) T7 Signal transducer time

constant in Power path 2.0 sec. 0.3070.0 T

sec. Ks2 Signal transducer gain in

Power path 0.402

HTw

21

0.520.0 Ks

Ks3 Integral of Electric Power gain

1.0 0.130.0 Ks


0.03 sec. 0.381.0 T sec.


0.012 sec. 0.1902.0 T sec.



0.18 sec. 0.510.0 T sec.

T2 First lead/lag lag time constant

0.11 sec. 0.520.0 T sec.


0.11 sec. 0.530.0 T sec.


0.04 sec. 0.540.0 T sec.

T10 Third lead/lag lead time constant (may be

provided by manufacturer)

1.0 sec. 0.5100.0 T sec.

T11 Third lead/lag lag time constant (may be


1.0 sec. 0.5110.0 T sec.


5 101 M


1 21 N

Vpssmax Stabilizer output maximum limit

0.05 pu 2.00 max Vpss

Vpssmin Stabilizer output minimum limit

-0.05 pu 0.02.0 min Vpss

7.2 McArthur Falls Units 1 to 8 Exciter Upgrades


Page 25

Similar studies which were performed to evaluate the transient stability performance of the proposed excitation system upgrades for the units at Great Falls, were performed for the eight units at McArthur Falls G.S.. The model of the commissioned static exciter and PSS for Great Falls Unit 3 was used to model proposed high initial response full static exciters for McArthur Falls. The eight units were modelled as they are in existing MAPP models as one aggregate unit. Figure 5 shows the rotor angle of the McArthur Falls generators following a three phase, five cycle clearing bus fault at the McArthur Falls 115 kV bus. Results confirm that the faster exciter will improve the speed of the steady state voltage regulation on the McArthur falls bus. Results also confirm that the faster exciter improves the “first swing” stability but degrades the local oscillatory mode. Simulations with a modified version of the Great Falls U3 PSS shows significant improvement in the damping provided to the local mode. For additional reasons discussed above, the McArthur Falls new excitation system should also come equipped with dual input PSS2A or PSS2B type stabilizers. Similar to Great Falls G.S., studies to date have not identified a need for contribution to inter-area mode damping from McArthur Falls..


Page 26

Figure 5: McArthur Falls Rotor Angle Following a 3ph, 5cy. Bus fault on the McArthur Falls 115 kV bus

Based on the improvements observed at Great Falls, line drop compensators are also recommended to be part of the McArthur Falls excitation system package.

One of the options to be considered for this station in the IES was the installation of static pilot exciters to replace the existing AVRs and to provide voltage regulation via the existing rotating main exciter. Considering the vintage of the existing McArthur Falls rotating exciters and the relative participation of these generators in the local oscillatory mode (see Small Signal Stability studies), it is recommended that this option not be considered.

Static pilot exciters may provide less excitation to local modes of oscillation following a disturbance but they also inhibit the effectiveness of PSSs in damping local modes in the vicinity due to the increased time lag introduced into the stabilizing loop because the PSS has to provide field modulation of the generator through the slower rotating main exciter. There are cases where PSSs have been added to static pilot exciters but with limited success.

Based on the above, the following are recommended for the McArthur Falls G.S. excitation systems for the eight units:






+6.0 pu and –5.0 pu, respectively. In this case, 1 pu field voltage shall be defined as the generator field voltage required to produce 1 pu terminal (stator) voltage on the open circuit air-gap line. If the rotors of these units are not sufficiently insulated to accommodate these limits then the highest field forcing limits allowable shall be used.


Page 27

The exciter voltage regulator shall be specified to include Line Drop Compensation (LDC). The available LDC shall range from zero to a minimum of 60% of step-up transformer impedance.



excitation system package. An IEEE PSS2B PSS is acceptable if there are small or no cost differences between the two and/or if the supplier does not supply the IEEE PSS2A. The PSS2B has a third lead/lag block which may be bypassed. Parameter ranges and study parameters for the PSS are shown in Table 4 below.

Table 4: McArthur Falls U1-8 Recommended PSS Parameter Ranges and Study Values


McArthur Falls U1-8 Recommended

Parameter Range Tw1 First washout time




sec. T6 Signal transducer time

constant in speed path 0.02 sec. .0.1060.0 T

sec. Tw3 First washout time

constant in power path 2.0 sec. 0.3030.0 Tw


constant in Power path


PSS/E)

0.3040.0 Tw sec.

( Set Tw4 High (30.0 sec.) if block cannot be




Power path 0.5814

HTw

21

0.520.0 Ks


1.0 0.130.0 Ks


0.03 sec. 0.381.0 T sec.


0.012 sec. 0.1902.0 T sec.



0.18 sec. 0.510.0 T sec.


0.11 sec. 0.520.0 T sec.


0.11 sec. 0.530.0 T sec.


0.04 sec. 0.540.0 T sec.


provided by

1.0 sec. 0.5100.0 T sec.


Page 28

Parameter Description Simulation Value McArthur Falls U1-8


manufacturer)



1.0 sec. 0.5110.0 T sec.


5 101 M


1 21 N




-0.05 pu 0.02.0 min Vpss

7.3 Slave Falls Units 1 to 8 Exciter Upgrades

Similar to the other two plants, high speed initial response exciters and PSSs were simulated on the eight units at Slave Falls using models of Great Falls commissioned Unit 3. Figure 6 shows the rotor angles of the Slave Falls units following a three phase, five cycle clearing bus fault on the 115 kV bus.


Page 29

Figure 6: Slave Falls Rotor Angle Following a 3ph, 5cy. Bus Fault on the Slave Falls 115 kV bus

Results show some reduction in rotor angle “first swing” with the faster exciter modelled. In this case both exciters seem to excite the local oscillatory mode. Again a PSS installed at this location provides very good damping to the local mode.

According to the IES Slave Falls G.S., was to receive consideration for a static pilot exciter installation. Similar arguments apply here which are further strengthened by the small signal study results below which shows that Slave Falls is the number one relative participant in the local oscillatory mode. Therefore full static exciters which enhance the effectiveness of PSSs installed at this location are recommended. Based on the Great Falls studies and the overall plan by Power Supply to enable LDCs on the Winnipeg River when the opportunity arises, LDCs are recommended for the Slave Falls units.

Based on the above, the following are recommended for the Slave Falls G.S. excitation systems for the eight units:






+6.0 pu and –5.0 pu, respectively. In this case, 1 pu field voltage shall be defined as the generator field voltage required to produce 1 pu terminal (stator) voltage on the open circuit air-gap line. Rotor insulation shall be specified to accommodate these limits.






Page 30

A standard IEEE PSS2A power system stabilizer, to be part of the excitation system package. An IEEE PSS2B PSS is acceptable if there are small or no cost differences between the two and/or if the supplier does not supply the IEEE PSS2A. The PSS2B has a third lead/lag block which may be bypassed. Parameter ranges and study parameters for the PSS are shown in Table 5 below.

Table 5: Slave Falls U1-8 Recommended PSS Parameter Ranges and

Study Values




2.0 sec. 0.3010.0 Tw sec.


2.0 sec. 0.3020.0 Tw sec.


0.02 sec. .0.1060.0 T sec.


2.0 sec. 0.3030.0 Tw sec.



PSS/E)

0.3040.0 Tw sec.

(Set Tw4 High (30.0 sec.) if block cannot be




Power path 0.3215

HTw

21

0.520.0 Ks


1.0 0.130.0 Ks


0.03 sec. 0.381.0 T sec.


0.012 sec. 0.1902.0 T sec.



0.18 sec. 0.510.0 T sec.


0.11 sec. 0.520.0 T sec.


0.11 sec. 0.530.0 T sec.


0.04 sec. 0.540.0 T sec.



1.0 sec. 0.5100.0 T sec.



1.0 sec. 0.5110.0 T sec.


5 101 M


1 21 N


Page 31






-0.05 pu 0.02.0 min Vpss

8. Small Signal Stability Studies

In this section of the IES, results from small signal stability studies conducted using eigenvalue analysis in SSAT are presented. Details on eigenvalue analysis can be found in references [8, 9, 10, 11, 12 and 13] and will not be reproduced here.

Briefly the state of the power system is analyzed in the frequency domain and the eigenvalues associated with various modes of oscillations identified. Further analysis is performed to determine the level of participation of each generator in a particular oscillatory mode by identifying and using the left and right eigenvectors associated with the eigenvalues of the mode. The results are usually normalized to the generator with the largest participation thereby assigning this generator a relative participation factor of 1.

From a practical perspective this is usually a good indication of where a damping controller, such as a PSS, may be located in order to maximize the damping provided to a particular mode. The eigenvalues are usually further separated into their frequency component, an indication of the frequency of oscillation of the particular mode, and their damping component, an indication of the time and/or cycles taken for a particularly excited mode to stabilize or reach steady state. The results in Figures 1, 2, 5 and 6 are examples of oscillatory modes with good and poor damping. The damping is usually represented by a mathematical expression referred to as the damping ratio.

Referring to the Transmission System Interconnection Requirements (TSIR) document, the damping criteria used by Manitoba Hydro is as follows:

A damping ratio which exceeds 0.05 (5%) is acceptable, between 0.03 (3%) and 0.05 (5%) is marginal and should be examined on a case by case basis, below 0.03 (3%) requires mitigation measures.

Eigenvalue analysis can be conducted for system intact (steady state) conditions and for contingency disturbance conditions. System intact, no-contingency eigenvalue analysis with proposed and existing PSSs on all Winnipeg River plants disabled, resulted in five distinct local modes of oscillation in the Manitoba Hydro south east system including the Winnipeg


Page 32

River area power system. These modes are summarized in Table 6 and are classified based on the dominant plants in the mode shape.

Table 6: Summary of Winnipeg River Local Oscillatory Modes

Mode 1 Mode 2 Mode 3 Mode 4 Mode 5

Dominant Plants

Pine Falls _ 7 Sisters

Pointe du Bois_Slave Falls

Slave Falls_Seven Sisters

McArthur Falls_Great Falls

Great Falls_Pine Falls

Frequency (Hz)

1.634 1.773 1.517 2.139 1.813

Damping Ratio (%)

10.820 14.330 10.440 9.660 19.350

Highest Relative Participating Plant

Pine Falls U1-6

Pointe du Bois U5-16

Slave Falls U1-8

McArthur Falls U1-8

Great Falls U1,2,4-6

Results show that none of these local oscillatory modes are in violation of the Manitoba Hydro damping criteria under steady state, system intact conditions. Figures 7 to 11 show details on other plants which form part of the mode shape and participate in the identified modes.

(a) (b)(a) (b)


Page 33

Figure 7: (a) Mode Shape and (b) Participating Generators in 1.635 Hz (Mode 1)


(a) (b)(a) (b)(b)

(a) (b)(a) (b)


Page 34



(a) (b)(a) (b)

(a) (b)(a) (b)


Page 35

Figure 11 :(a) Mode Shape and (b) Participating Generators in 1.813 Hz (Mode 5)

Using the PSS parameters proposed in Section 7 for the generators at Great Falls, McArthur Falls and Slave Fall, the effects of these PSSs on the damping of local Modes 1 to 5 was assessed.

With all other Winnipeg River PSSs out of service, the PSSs on the Great Falls units were enabled and their gains collectively adjusted. The PSSs at Great Falls had negligible effects on the damping of Modes 1, 2, 3 and 4. Figure 12 shows a root locus of the eigenvalues associated with Mode 5, the 1.813 Hz mode as the gains on the Great Falls PSSs are collectively adjusted. Since the Great Falls generators showed significantly higher relative participation in this mode than other Winnipeg River plants the effect of its PSSs on the damping of this mode is not surprising.

Similarly with all other PSSs disabled (gains set to 0) the gain on the Slave Falls PSS was adjusted from 0 to 6. The effect on modes other than Mode 3, the 1.52 Hz mode, is negligible. A root locus plot is shown in Figure 13. Again due to the fact that the Slave Falls units are top participants in this mode the results are consistent with expectations. Based on the relatively high participation of Pointe du Bois as well as Seven Sisters units in this local oscillatory mode, it is conceivable that PSSs at these locations will also positively affect the damping on this mode. IES reports, references [15] and [16] document stability studies pertaining to the refurbishment of Pointe du Bois G.S..


Page 36

8

10

12

-4.5 -4 -3.5 -3 -2.5 -2 -1.5

Eigenvalue Real (rad/sec)

Eig

en

va

lue

Ima

gin

ary

(ra

d/s

ec

)K=0f =1.813Hzζ =19.35 %

K=0.5f =1.72Hzζ =26.53 %

K=6f =1.42 Hzζ =40.57 %

Figure 11: Root Locus of 1.812 Hz mode (Mode 5) due to Great Falls PSS gain

6

8

10

12

-3 -2.5 -2 -1.5 -1 -0.5


Eig

en

va

lue

Ima

gin

ary

(ra

d/s

ec

)

K=0f =1.52 Hzζ =10.44 %

K=2f =1.47 Hzζ =16.47 %

K=6f =1.3 Hzζ =31.6 %

6

8

10

12

-3 -2.5 -2 -1.5 -1 -0.5


Eig

en

va

lue

Ima

gin

ary

(ra

d/s

ec

)

K=0f =1.52 Hzζ =10.44 %

K=2f =1.47 Hzζ =16.47 %

K=6f =1.3 Hzζ =31.6 %

Figure 12: Root Locus of 1.517 Hz mode (Mode 3) due to Slave Falls PSS gain

With other PSSs disabled the gain on the McArthur PSS was adjusted from 0 to 6. The effect on modes other than Mode 4, the 2.14 Hz mode, is negligible. A root locus plot is shown in Figure 14. Results are consistent


Page 37

with the relative participation factors and mode shape results shown in Figure 10 for Mode 4. Small gain adjustments results in significant improvements in damping on this mode.

8

10

12

14

-4.5 -4 -3.5 -3 -2.5 -2 -1.5 -1 -0.5


Eig

enva

lue

Imag

inar

y (r

ad/s

ec)

K=0f =2.14 Hzζ =9.66 %

K=2f =1.96 Hzζ =24.58 %

K=6f =1.56 Hzζ =37.66 %

Figure 14: Root Locus of 2.14 Hz mode (Mode 4) due to McArthur Falls PSS gain

Results from the small signal stability study are consistent with those from the transient stability study showing that high speed full static exciters are desirable for Great Falls, McArthur Falls and Slave Falls generating stations. Even though the damping on local modes in the area is not a concern based on Manitoba Hydro’s damping criteria, the relatively low costs associated with adding PSSs to a full static exciter package suggests that PSSs should be included in the full static exciter packages. Based on simulation results, these PSSs will add significant damping to the Manitoba Hydro southern system. PSSs are not required to provide damping to inter-area modes since studies do not show any significant participation of the plants in inter-area modes.


Page 38

9. Governor Replacement Considerations

Part of this IES for Great Falls, McArthur Falls and Slave Falls was to

determine if there are any system benefits to be derived from replacing existing electro-mechanical governors at these three plants with digital governors.

Existing governor models at the three plants were replaced with models of

digital governors similar to those at Limestone G.S. and full load rejections simulated. Results are shown in Figures 15, 16 and 17.

Figure 15: Simulated full load rejection at Great Falls with existing and digital governor models


Page 39

Figure 16: Simulated full load rejection at McArthur Falls with existing and digital

governor models

Results do not indicate any detrimental effects to the power system by replacing existing governors with digital governors at the three plants. Results also indicate proposed digital governors may provide better dynamic response of the units following load rejections, although the improvement is not significant to the overall operation of the power system. This benefit would be more evident if part or the whole Manitoba Hydro system becomes isolated.


Page 40

Figure 17: Simulated full load rejection at Slave Falls with existing and digital governor models

Different suppliers provide different forms of speed governing systems. The specification for digital governors should be as broad as possible. Standard governor requirements are provided in the ANSI/IEEE Standard 125-2005, “IEEE Recommended Practice for Preparation of Equipment Specifications for Speed-Governing of Hydraulic Turbines Intended to Drive Electric Generators”. Some of the functional requirements provided here will be based on the IEEE guide as well as those developed for Wuskwatim [7]. Based on the above it is recommended that governors be specified according to the parameter ranges shown in Table 7 below.


Page 41

Table 7: General Governor Specifications for Great Falls, McArthur Falls and Slave Falls


Permanent Droop/Speed Regulation

Adjustable from 0 to 10% in steps of 1%

4%

Dead Band Should not exceed 0.036 Hz 0.0 Dead Time For step load change of more

than 10% of capacity of turbine, dead time shall not exceed 0.2 seconds

0.0 sec.

Temporary Speed Droop Time Constant

This parameter shall be continuously adjustable from 0 to 30 seconds.

6.1 sec.

Temporary Speed Droop

Shall be continuously adjustable from 0 to 150 %.

36.0 %

Proportional Gain Shall be continuously adjustable from 0 to 20

1.0 pu

Derivative Gain Shall be continuously adjustable from 0 to 5 seconds

0.0 sec.

Integral Gain Shall be continuously adjustable from 0 to 10 per second

0.0 sec-1

10. Stability Model Requirements

For re-runnered and re-wound units at Great Falls and Slave Falls, the supplier shall provide new generator reactance values for all parameters affected by the refurbishment work.

10.1 Stability Model Requirements for Governors

Details on governor models and model simulation requirements can be found in reference [17]. Some of the requirements are summarized here. All model validation, testing, documentation and reporting shall conform to those specified in the IEEE Std. 125-2007 “IEEE Recommended Practice for Preparation of Equipment Specifications for Speed-Governing of Hydraulic Turbines Intended to Drive Electric Generators” [19], Section 5 of the Midwest Reliability Organization (MRO) Generating Testing Guideline [18] and Section 3.7 of the Transmission System Interconnection Requirements (TSIR) document [14].


Page 42

To demonstrate that the governor is capable of controlling the speed and power of the turbine at all power output levels, in a stable manner, under isolated or interconnected unit conditions, the supplier shall prove the following by way of computer simulations under steady-state and transient conditions:

(i) The governor is fully responsive to frequency deviations exceeding ±

0.036 Hz [14];

(ii) The governor supports continuous, stable and reliable operation of the generating unit for fundamental frequency variations of 60 ± 0.5 Hz [14];

(iii) The governor supports continuous, stable and reliable operation of the

generating unit for system frequency variations between 58 and 63.5 Hz which lasts for less than or equal to 30 seconds [7, 14];

(iv) Simulation of a load rejection between zero and any load within the

capability of the turbine shall show that speed will be returned to the speed reference with no more than one under-speed deviation not to exceed 5% and one overspeed deviation not to exceed 5% after the initial overspeed deviation [19];

(v) Simulation of an on-line speed reference step change not less than 5%

with demonstrated stable governor response [18].

(vi) Stability studies shall cover the operating range between maximum and minimum net heads with the discharge corresponding to full load under each respective net head [7, 14];

(vii) Following stability studies the supplier shall indicate the actual setting

as well as setting ranges of the governor parameters for which the control circuit remains stable after any disturbance [7, 14].

In addition to the above computer simulations to demonstrate stable operation of the governor, a verified detailed mathematical computer model of the governor functionality shall be provided for use in detailed planning studies. This model shall be accompanied by a block diagram detailing the governor functionality, detailed parameter settings and parameter ranges and detailed documentation. Verification of the mathematical models of the governors shall be completed according to Section 8.1.6 of the IEEE Standard 125 - 2007 [18]. As outlined in [18], verification shall be accomplished by completing either a frequency response, time response or both to demonstrate that the


Page 43

governor control system responds in a manner consistent with the specified mathematical computer model. This detailed model shall be compatible with PSS/E V29 or later and PSCAD/EMTDC V 4.2.1 or later, power system simulation programmes. In addition to the detailed model above, the supplier shall provide to Manitoba Hydro, a simplified non-proprietary, standard IEEE model of the governor controls, as per those described in the IEEE working group document on Hydraulic Turbine and Turbine Control Models for System Dynamics (see reference [20]). These models shall be compatible with PSS/E V29 or later and PSCAD/EMTDC V4.2.1 or later. The models will be used for interconnection type studies in which model information may be freely shared with other internal and external stakeholders.

10.2 Stability Model Requirements for Excitation System Controls

Detailed and Standard IEEE models of all excitation system controls, including regulator, limiter and protection controls shall be provided by the supplier. It is expected that the following be included:

(a) Verified detailed mathematical computer models of the excitation

system functionality shall be provided for use in detailed planning studies. This model shall be accompanied by a block diagram detailing the excitation system functionality, detailed parameter settings and parameter ranges and detailed documentation.

(b) Clear functional block diagrams of recommended IEEE models; (c) Clear descriptions of each parameter along with units;

(d) Clear indication of parameter values used during Factory Acceptance Tests along with the adjustable design range of each parameter; and

(e) Clear indication of all limits along with adjustable limit ranges.

It is anticipated that these models will be used in system studies and for Midwest Reliability Organization (MRO) and North American Electric Reliability Council (NERC) equipment verification tests. The models shall be compatible with PSS/E V29 or later and PSCAD/EMTDC V4.2.1 or later. These models will be used for interconnection type studies in which model information may be freely shared with other internal and external stakeholders.


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11. References

[1] Manitoba Hydro Report, “Great Falls Accreditation Studies”, submitted to MAPP Design Review Subcommittee, 2003 07 14.

[2] B.A. Archer, “Great Falls Unit 3 Static Exciter and Power System

Stabilizer”, System Planning Interoffice Memorandum to J.B. Davies, TM 01/2, 2001 03 28.

[3] J.Luis Gonçalves, “ABB Commissioning Report on Great Falls Unitrol-

F on Generator #3”, Report to Manitoba Hydro, 2003 08 19. [4] M.S. Abdel-Hadi, “Great Falls Unit #3 AVR and PSS Settings”, System

Performance Interoffice Memorandum to J.B. Davies, 2003 08 06. [5] B.A. Archer, “Great Falls Unit 3 Stability Models”, System Planning

Interoffice Memorandum to J.B. Davies, TM 03/22, 2003 09 05. [6] G. Evans, “Pine Falls Generating Station Facility Upgrade

Interconnection Facility Study (Draft), File 7-2D, 2008 05 01. [7] B.A. Archer, “Wuskwatim Generating Station Requirements for

Generators and Controls”, System Planning Department Report, SPD 02/7, March 25, 2003.

[8] B.A. Archer, “Kelsey Exciter Replacement – Static Exciter and

Stabilizer Considerations”, System Planning Interoffice Memorandum to J.B. Davies, File 7-3, 2000 10 11.

[9] B.A. Archer, “Kettle Units on AC – Stabilizer Considerations”, System Planning Interoffice Memorandum to J.B. Davies, TM 97/09, 1997 12 23.

[10] Prabha Kundur, “Power System Stability and Control”, McGraw Hill

Inc., 1994. [11] P. Kundur, G.J. Rogers, D.Y. Wong, L. Wang and M.G. Lauby, “A

Comprehensive Computer Program Package for Small Signal stability Analysis of Power Systems”, IEEE Transactions on Power Systems, Vol. 5, No. 4, November 1990.

[12] D.C. Lee, P. Kundur, “Advanced Excitation Controls For Power System

Stability Enhancement”, Proceedings of CIGRE International Conference on Large High Voltage Electric Systems, Paris, 1986.

[13] P. Calic, “Oscillations in the Northern Collector System”, System


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Planning Department Report, SPD 2008/13, 2008 06 05. [14] Manitoba Hydro, “Transmission System Interconnection

Requirements”, TSIR Revision 0, December 2003. [15] T. Young, “Pointe Du Bois Redevelopment IES (Draft)” September,

2005. [16] G. Virch, “Pointe Du Bois Generator Redevelopment IES (Draft), May

16 2008. [17] B. A. Archer, “Specifications for Computer Simulations of Wuskwatim

Governor Controls”, System Planning Technical Memorandum to J.B. Davies, TM08/04, 2008 04 29.

[18] MRO Generator Testing Review Task Force, “MRO Generator Testing

Guidelines”, Approved by the MRO Board of Directors, March 2007. [19] IEEE Energy Development and Power Generation Committee”, IEEE

Recommended Practice for Preparation of Equipment Specifications for Speed-Governing of Hydraulic Turbines Intended to Drive Electric Generators”, IEEE Std. 125-2007, IEEE Power Engineering Society, October 2007.

[20] IEEE Working Group on Prime Mover and Energy Supply Models for

System Dynamic Performance Studies, “Hydraulic Turbine and Turbine Control Models for System Dynamic Studies”, IEEE Transactions on Power Systems, Vol. 7, No. 1, February 1992.


Page 46

APPENDIX A: Interconnection Evaluation Study Agreements


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ATTACHMENT 2

INTERCONNECTION EVALUATION STUDY AGREEMENT

FOR Great Falls Generating Station

THIS AGREEMENT is made and entered into this 23 day of May, 2008 by and between Manitoba Hydro (Power Supply Business Unit), a corporation incorporated pursuant to the provisions of The Manitoba Hydro Act, R.S.M. 1987, c.H190, [corporate description of Generator] existing under the laws of the Province of Manitoba, sometimes hereinafter referred to as "Generator," and Manitoba Hydro, a corporation incorporated pursuant to the provisions of The Manitoba Hydro Act, C.C.S.M. c.H190. Generator and Manitoba Hydro each may be referred to as a "Party," or collectively as the "Parties."

RECITALS

WHEREAS, Generator has submitted an Interconnection Request to Manitoba Hydro pursuant to the terms and conditions of the Manitoba Hydro Open Access Interconnection Tariff with respect to a generating facility located or to be located at the Great Falls Generating Facility (Facility); and WHEREAS, Generator has requested that Manitoba Hydro prepare an Interconnection Evaluation Study to assess the impact of the Interconnection Request on the reliability of the Manitoba Hydro System, and of any other affected systems; NOW, THEREFORE, in consideration of and subject to the mutual covenants contained herein, it is agreed as follows:

1.0 The terms used in this Agreement shall have the meanings specified in the Manitoba Hydro Open Access Interconnection Tariff.

2.0 Manitoba Hydro shall perform or cause to be performed an

Interconnection Evaluation Study and prepare an Interconnection Evaluation Study Report in accordance with the Manitoba Hydro Open Access Interconnection Tariff.

3.0 As described in the Manitoba Hydro Open Access Interconnection Tariff,

Generator elects to have Phase 1 and Phase 2 performed (X) concurrently or (__) sequentially (select one option). This election is not available for Resource Solicitation Studies.


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3.1 If Phase 1 and Phase 2 are performed concurrently, Manitoba Hydro estimates that it will be able to complete the Interconnection Evaluation Study Report on or before October 30, 2008.

3.2 If the Generator elects to have Phase 1 and Phase 2 performed

sequentially, Manitoba Hydro estimates that it will be able to complete the preliminary report on Phase 1 of the Interconnection Evaluation Study on or before .

4.0 The scope of the Interconnection Evaluation Study (“Study”) shall be as

set forth in the Manitoba Hydro Open Access Interconnection Tariff subject to the assumptions set forth in Exhibit A of this Agreement.

5.0 The Study shall be based on the technical information provided by

Generator in Exhibit B to this Agreement. Manitoba Hydro reserves the right to request additional technical information from Generator as may become necessary during the course of the Interconnection Evaluation Study. If Generator’s Interconnection Request is modified or the technical information provided in Exhibit B is modified, incomplete, or inaccurate, the time to complete the Interconnection Evaluation Study may be extended and/or the results may be inaccurate.

6.0 The final Interconnection Evaluation Study Report (“Study Report”)

shall provide the following information:

(i) Identification of any thermal overload or voltage limit violations resulting from the interconnection.

(ii) Identification of any circuit breaker short circuit capability

limits exceeded as a result of the interconnection. (iii) Identification of any instability or inadequately damped

response to system disturbances resulting from the interconnection.

(iv) A preliminary identification of the Transmission Owner

Interconnection Facilities and Interconnection System Upgrades required to accommodate the Interconnection Request.

(v) A preliminary, non-binding estimate of the costs and time

required to construct the Transmission Owner Interconnection Facilities and Interconnection System Upgrades.

7.0 Generator shall make an initial payment of the estimated cost for

performance of the Study and preparation of Study Report in the


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amount of $43,000.00 minus the $10,000 deposit = $33,000.00 at the time of delivering the executed Agreement to Manitoba Hydro. Manitoba Hydro shall charge and Generator shall pay for all actual costs of the Study and Study Report (including the provision of supporting documentation) in excess of the deposit paid by Generator (at the time of submitting its Interconnection Request) after completion of the Study Report or withdrawal or termination of the Interconnection Request, whichever occurs first. Actual costs of the Study and Study Report shall include overhead costs. Such payment shall be due and payable within 30 days of the Generator being invoiced unless Generator’s Interconnection Request is terminated for insolvency pursuant to Section 16.2 of the Manitoba Hydro Open Access Interconnection Tariff, in which case the provisions of Section 16.2 of the Tariff shall apply. If after completion of the Study Report or upon withdrawal or termination of the Interconnection Request, the deposit paid by Generator exceeds the actual costs of the Study and preparation of the Study Report, Manitoba Hydro shall refund the excess amount to the Generator within 30 days or, at the direction of the Generator, apply the excess amount towards the costs of an Interconnection Facilities Study.

8.0 Actual interconnection of the Facility shall be subject to the

provisions of the Manitoba Hydro Open Access Interconnection Tariff and applicable regulatory and any other required approvals.

9.0 This Agreement is subject to the provisions of the Manitoba Hydro

Open Access Interconnection Tariff and the provisions of said Tariff are incorporated by reference herein.

10.0 This Agreement shall be governed and interpreted in accordance

with the laws of the Province of Manitoba.

11.0 This Agreement shall not be assigned without the prior written consent of the other Party.

12.0 Any amendments to this Agreement shall be in writing and signed

by the Parties.

13.0 This Agreement constitutes the entire agreement between the parties with respect to the subject matter hereof and terminates and supersedes all prior oral and written representations. There are no representations, conditions, warranties or agreements, express or implied, with respect to or collateral to this Agreement other than those contained or expressly incorporated herein.

14.0 Manitoba Hydro is an independent contractor. This Agreement

shall not create the relationship of employer and employee,


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principal and agent, partnership or joint venture between Manitoba Hydro and Generator or between Generator and any officers, employees or agents of Manitoba Hydro.

15.0 Generator acknowledges that Manitoba Hydro is relying upon

information provided by the Generator and other parties in the preparation of the Study and Study Report.

16.0 Manitoba Hydro makes no representations or warranties with

respect to the accuracy, completeness, reliability or suitability of the Study and Study Report. Generator assumes any and all risk and responsibility for use of, and reliance on, the Study and Study Report. Generator disclaims and waives any rights or remedies that it might otherwise have against Manitoba Hydro in contract, tort, equity or other legal cause of action for faults, errors, defects, inaccuracies, omissions, suitability or reliability of the Study and Study Report.

17.0 Generator agrees to indemnify and hold harmless Manitoba Hydro

and its successors and assigns from and against all actions, causes of action, claims, damages, costs, liability, debts, demands, damage to property or persons, including damages, costs and losses suffered by Manitoba Hydro and claims brought against Manitoba Hydro by any third party whatsoever, in respect of, or arising directly or indirectly out of this Agreement.

18.0 All products of, or resulting from, the performance of the Study and

preparation of the Study Report by Manitoba Hydro in the course of performing this Agreement, including but not limited to, all information, drawings, Reports, records, documents, research notes, data, photographs, maps, materials, drafts, working drafts, documents or tangible assets and any intellectual property therein, including patent, trademark, copyrights, design and trade secrets (hereinafter collectively referred to as “Service Product”) shall become the exclusive property of Manitoba Hydro immediately upon creation or assembly, notwithstanding the fact that all or a portion of the data provided by Generator may be incorporated within the Service Product. The Generator shall have no right to copy, modify, amend, alter, sell, lend or dispense of any such Service Products in any manner for any reason.

19.0 The Generator shall have no right to use the Service Products

except for the purpose of determining whether the Generator shall proceed with having Manitoba Hydro perform an Interconnection Facilities Study.

20.0 Neither Party shall be considered in default as to any obligation

under this Agreement if prevented from fulfilling the obligation due


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to an event of Force Majeure. However, a Party whose performance under this Agreement is hindered by an event of Force Majeure shall make all reasonable efforts to perform its obligations under this Agreement. Neither Party shall be relieved of liability for failure of performance to the extent that such failure is due to a remediable cause which it fails to remove or remedy within a reasonable period of time.

20.1 In this Agreement, an event of “Force Majeure” means any act of

God, labour disturbance, act of the public enemy, war, insurrection, riot, fire, storm or flood, explosion, breakage or accident to machinery or equipment, any order, regulation or restriction imposed by governmental, military or lawfully established civilian authorities, or any other cause beyond a Party’s reasonable control which cause could not have been avoided by the exercise of Good Utility Practice. A Force Majeure event does not include an act of negligence or intentional wrongdoing or economic hardship or insolvency.

20.2 If there is a Force Majeure event that has affected a Party’s ability

to perform its obligations under this Agreement the Party shall forthwith (and in any event no later than the end of the next business day after it first becomes aware that an occurrence constitutes a Force Majeure event) notify the other Party in writing of the reasons why it believes the occurrence constitutes a Force Majeure event, identifying the nature of the event, its expected duration, and the particulars of the obligations affected by the event, and furnish to the other Party reports with respect to the Force Majeure event at such intervals as the other Party may reasonably request during the continuance of the Force Majeure event.

20.3 If there is a Force Majeure event affecting a Party’s ability to

perform its obligations under this Agreement, the Party shall be prompt and diligent in removing, if practicable, the cause of such inability to perform, but nothing in this Agreement shall be construed as permitting a Party to continue to fail to perform after said cause has been removed. Notwithstanding the foregoing, a Party shall not be obligated to agree to any settlement of a strike or labour dispute which, in that Party’s sole opinion, may be inadvisable or detrimental.

21.0 This Agreement may be executed in any number of counterparts,

including counterparts signed by facsimile, each of which shall be deemed an original and all of which together shall constitute one and the same instrument. A photocopied and/or facsimile copy of this Agreement bearing a signature of each Party, in a single


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document or as counterparts thereof as provided for herein, shall be deemed an original executed version of this Agreement.


Page 53

IN WITNESS WHEREOF, the Parties have caused this Agreement to be

duly executed by their duly authorized officers or agents on the day and year first above written. Manitoba Hydro Manitoba Hydro

Transmission and Distribution Power Supply

Business Unit Business Unit

By: _________________________________ By:

________________________________

Name : Ron Mazur Name (typed or printed):

_______________

Title: Manager T & D System Planning Title:

______________________________


Page 54

EXHIBIT A

to Interconnection Evaluation Study Agreement For

Great Falls Generating Facility

The Interconnection Evaluation Study will evaluate the impact of 3 MW of additional generation and a substantial modification to the unit excitation and governors connected to the Great Falls 115 kV switchyard, at the point designated for the location of the site at Great Falls Generating Station on the Winnipeg River, near the town of Great Falls, Manitoba, with a projected In-Service Date of 2009. The Interconnection Evaluation Study will be completed in two phases; (i) In one phase the upgrades to unit excitation and governors will be studied

in conjunction with Pine Falls G.S.(units 1-6), Great Falls G.S.(units 1,2,5 & 6), Slave Falls G.S.(units 1-6) and McArthur Falls G.S (units 1-8) based upon the following: a. Existing Automatic Voltage Regulators (AVRs) and rotating main

exciters replaced with full static exciters and; b. Existing electro mechanical governors replaced with digital governors. c. The study will investigate options at McArthur Falls G.S in order to

recommend either full static excitation systems or static pilot exciters to function with existing rotating main exciters.

The study will assume that Great Falls units 3 & 4 are already equipped with full static exciters and that all proposed full static exciters for the generating stations under consideration will be of similar type (functionality and speed of response) to the ABB full static excitation systems with modern power system stabilizers, recently installed on Great Falls units 3 & 4. Studies will be performed with the assumption of Pointe du Bois G.S. as it exists today and with some anticipated features of the proposed redevelopment. The study will consider steady state, transient and small signal stability effects of the new excitation and digital governors systems versus existing ones from a system perspective (Manitoba Hydro as well as the surrounding MRO interconnected system). Studies will be conducted under several simulated system scenarios, generator loading and seasonal conditions. The deliverables from the study will include conclusions and recommendations pertaining to the procurement of generator protection and control equipment, equipment ratings, control parameter design ranges along with settings used in the study.


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This portion of the Interconnection Evaluation Study may be completed earlier than the Interconnection Evaluation Study report. The estimated cost for this part of the study is $10,000.00.

(ii) The second phase of the Interconnection Evaluation Study will investigate the possible generation increase of an additional 3 MW of Network Resource Interconnection Service. The second phase of the Interconnection Evaluation /study will be based upon the following assumptions:

The generation output associated with the Unit 3 and 4 re-runnering project will exceed the original 8 MW increase in generation studied for the project in the IFS report dated July 14 2003. The 3 MW increase exceeds the approved Facility generation level of 139.6 MW of Network Resource Interconnection Service associated with the project and the IFS report dated July 14 2003. This phase of the study is estimated to cost $33,000.00.

Study Models

1. Steady-state post-disturbance analysis

a. This study will utilize MAPP PSS/E models 2007 series models:

2012 summer off peak (70% peak load)


Study will investigate new 115kV breaker configuration and local contingencies only. Study parameters will be adjusted to include the preceding projects identified by the ISDs within the generation queue. The maximum power export from Manitoba to the US is 2175 MW. Transfers to the US will be maximized based on available accredited generation above native load, allowing for spinning reserve.


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b. Transient stability analysis

2007 series MAPP models:

2012 and 2017 summer off peak with maximum (725 MW) Winnipeg River generation.

2. Transient stability analysis The following NERC category B (single component) and C (multiple components) disturbances will be tested to determine the impact on transfer capability and overall system stability within Manitoba using the 2012 summer-peak stability model:

i. 3-phase normal clearing faults with system intact ii. Single line to ground stuck breaker (slow clearing) faults with

system intact

4. Interconnection System and Network Upgrades Solutions to any limitations discovered during steady-state post-

disturbance and transient stability analysis will be determined. 5. Short Circuit Analysis Short Circuit Analysis is required to asses any increased short circuit levels on proposed new breaker layout. Three phase and single-line-to-ground fault levels will be calculated with PSS/E.


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ATTACHMENT 2

INTERCONNECTION EVALUATION STUDY AGREEMENT FOR McArthur Falls Generating Station

THIS AGREEMENT is made and entered into this 23 day of May, 2008 by

and between Manitoba Hydro (Power Supply Business Unit), a corporation incorporated pursuant to the provisions of The Manitoba Hydro Act, R.S.M. 1987, c.H190, [corporate description of Generator] existing under the laws of the Province of Manitoba, sometimes hereinafter referred to as "Generator," and Manitoba Hydro, a corporation incorporated pursuant to the provisions of The Manitoba Hydro Act, C.C.S.M. c.H190. Generator and Manitoba Hydro each may be referred to as a "Party," or collectively as the "Parties."

RECITALS

WHEREAS, Generator has submitted an Interconnection Request to Manitoba Hydro pursuant to the terms and conditions of the Manitoba Hydro Open Access Interconnection Tariff with respect to a generating facility located or to be located at the McArthur Falls Generating Facility (Facility); and WHEREAS, Generator has requested that Manitoba Hydro prepare an Interconnection Evaluation Study to assess the impact of the Interconnection Request on the reliability of the Manitoba Hydro System, and of any other affected systems; NOW, THEREFORE, in consideration of and subject to the mutual covenants contained herein, it is agreed as follows:






3.1 If Phase 1 and Phase 2 are performed concurrently, Manitoba Hydro

estimates that it will be able to complete the Interconnection Evaluation Study Report on or before October 30, 2008.


sequentially, Manitoba Hydro estimates that it will be able to complete the


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preliminary report on Phase 1 of the Interconnection Evaluation Study on or before .
















performance of the Study and preparation of Study Report in the amount of $10,000.00 minus the $10,000 deposit = $0.00 at the time of delivering the executed Agreement to Manitoba Hydro. Manitoba Hydro shall charge and Generator shall pay for all actual costs of the Study and Study Report (including the provision of supporting documentation) in excess of the deposit paid by Generator (at the time of submitting its Interconnection Request)


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after completion of the Study Report or withdrawal or termination of the Interconnection Request, whichever occurs first. Actual costs of the Study and Study Report shall include overhead costs. Such payment shall be due and payable within 30 days of the Generator being invoiced unless Generator’s Interconnection Request is terminated for insolvency pursuant to Section 16.2 of the Manitoba Hydro Open Access Interconnection Tariff, in which case the provisions of Section 16.2 of the Tariff shall apply. If after completion of the Study Report or upon withdrawal or termination of the Interconnection Request, the deposit paid by Generator exceeds the actual costs of the Study and preparation of the Study Report, Manitoba Hydro shall refund the excess amount to the Generator within 30 days or, at the direction of the Generator, apply the excess amount towards the costs of an Interconnection Facilities Study.









by the Parties.



shall not create the relationship of employer and employee, principal and agent, partnership or joint venture between Manitoba Hydro and Generator or between Generator and any officers, employees or agents of Manitoba Hydro.


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24.0 Generator acknowledges that Manitoba Hydro is relying upon information provided by the Generator and other parties in the preparation of the Study and Study Report.










under this Agreement if prevented from fulfilling the obligation due to an event of Force Majeure. However, a Party whose performance under this Agreement is hindered by an event of Force Majeure shall make all reasonable efforts to perform its obligations under this Agreement. Neither Party shall be relieved of


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liability for failure of performance to the extent that such failure is due to a remediable cause which it fails to remove or remedy within a reasonable period of time.








including counterparts signed by facsimile, each of which shall be deemed an original and all of which together shall constitute one and the same instrument. A photocopied and/or facsimile copy of this Agreement bearing a signature of each Party, in a single document or as counterparts thereof as provided for herein, shall be deemed an original executed version of this Agreement.


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By: _________________________________ By:

________________________________


_______________


______________________________


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EXHIBIT A


McArthur Falls Generating Facility

The Interconnection Evaluation Study will evaluate the impact of a substantial modification to the unit excitation and governors connected to the McArthur Falls 115 kV switchyard, at the point designated for the location of the site at McArthur Falls Generating Station on the Winnipeg River, near the town of Great Falls, Manitoba, with a projected In-Service Date of 2011. (iii) In one phase the upgrades to unit excitation and governors will be studied






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The estimated cost for the McArthur Falls Generating Station portion of the study is $10,000.00.


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ATTACHMENT 2

INTERCONNECTION EVALUATION STUDY AGREEMENT FOR Slave Falls Generating Station

THIS AGREEMENT is made and entered into this 23 day of May, 2008 by

and between Manitoba Hydro (Power Supply Business Unit), a corporation incorporated pursuant to the provisions of The Manitoba Hydro Act, R.S.M. 1987, c.H190, [corporate description of Generator] existing under the laws of the Province of Manitoba, sometimes hereinafter referred to as "Generator," and Manitoba Hydro, a corporation incorporated pursuant to the provisions of The Manitoba Hydro Act, C.C.S.M. c.H190. Generator and Manitoba Hydro each may be referred to as a "Party," or collectively as the "Parties."

RECITALS

WHEREAS, Generator has submitted an Interconnection Request to Manitoba Hydro pursuant to the terms and conditions of the Manitoba Hydro Open Access Interconnection Tariff with respect to a generating facility located or to be located at the Slave Falls Generating Facility (Facility); and WHEREAS, Generator has requested that Manitoba Hydro prepare an Interconnection Evaluation Study to assess the impact of the Interconnection Request on the reliability of the Manitoba Hydro System, and of any other affected systems; NOW, THEREFORE, in consideration of and subject to the mutual covenants contained herein, it is agreed as follows:






3.1 If Phase 1 and Phase 2 are performed concurrently, Manitoba Hydro

estimates that it will be able to complete the Interconnection Evaluation Study Report on or before October 30, 2008.


sequentially, Manitoba Hydro estimates that it will be able to complete the


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preliminary report on Phase 1 of the Interconnection Evaluation Study on or before .
















performance of the Study and preparation of Study Report in the amount of $43,000.00 minus the $10,000 deposit = $33,000.00 at the time of delivering the executed Agreement to Manitoba Hydro. Manitoba Hydro shall charge and Generator shall pay for all actual costs of the Study and Study Report (including the provision of supporting documentation) in excess of the deposit paid by Generator (at the time of submitting its Interconnection Request)


Page 67

after completion of the Study Report or withdrawal or termination of the Interconnection Request, whichever occurs first. Actual costs of the Study and Study Report shall include overhead costs. Such payment shall be due and payable within 30 days of the Generator being invoiced unless Generator’s Interconnection Request is terminated for insolvency pursuant to Section 16.2 of the Manitoba Hydro Open Access Interconnection Tariff, in which case the provisions of Section 16.2 of the Tariff shall apply. If after completion of the Study Report or upon withdrawal or termination of the Interconnection Request, the deposit paid by Generator exceeds the actual costs of the Study and preparation of the Study Report, Manitoba Hydro shall refund the excess amount to the Generator within 30 days or, at the direction of the Generator, apply the excess amount towards the costs of an Interconnection Facilities Study.









by the Parties.



shall not create the relationship of employer and employee, principal and agent, partnership or joint venture between Manitoba Hydro and Generator or between Generator and any officers, employees or agents of Manitoba Hydro.


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33.0 Generator acknowledges that Manitoba Hydro is relying upon information provided by the Generator and other parties in the preparation of the Study and Study Report.










under this Agreement if prevented from fulfilling the obligation due to an event of Force Majeure. However, a Party whose performance under this Agreement is hindered by an event of Force Majeure shall make all reasonable efforts to perform its obligations under this Agreement. Neither Party shall be relieved of


Page 69

liability for failure of performance to the extent that such failure is due to a remediable cause which it fails to remove or remedy within a reasonable period of time.








including counterparts signed by facsimile, each of which shall be deemed an original and all of which together shall constitute one and the same instrument. A photocopied and/or facsimile copy of this Agreement bearing a signature of each Party, in a single document or as counterparts thereof as provided for herein, shall be deemed an original executed version of this Agreement.


Page 70





By: _________________________________ By:

________________________________


_______________


______________________________


Page 71

EXHIBIT A


Slave Falls Generating Facility

The Interconnection Evaluation Study will evaluate the impact of 28 MW of additional generation and a substantial modification to the unit excitation and governors connected to the Slave Falls 138 kV switchyard, at the point designated for the location of the site at Slave Falls Generating Station on the Winnipeg River, near the town of Pointe du Bois, Manitoba, with a projected In-Service Date of 2009. The Interconnection Evaluation Study will be completed in two phases;

(iv) In one phase the upgrades to unit excitation and governors will be studied






Page 72

This portion of the Interconnection Evaluation Study may be completed earlier than the Interconnection Evaluation Study report. The estimated cost for this part of the study is $10,000.00.

(v) The second phase of the Interconnection Evaluation Study will investigate the possible generation increase of an additional 30 MW of Network Resource Interconnection Service. The second phase of the Interconnection Evaluation Study will be based upon the following assumptions:

A potential re-runnering project of Slave Falls units 1 to 6 and possibly units 7 and 8 with a potential generation increase of up to 30 MW in two incremental steps over the current 68 MW of Network Resource Interconnection Service. The upgrade may only require 6 units with the efficiency of the new runners, when available further details should be provided before the completion of the study. This study will investigate the Slave Falls Generating Station with a generation output of;

1. 83 MW with 6 units, 2. 98 MW with 6 units, and 3. 98 MW with 8 units.

This phase of the study may be able to take advantage of the results of a previous study for the new facility at Pointe du Bois and is estimated to cost $18,000.00.

Study Models

1. Steady-state post-disturbance analysis

a. This study will utilize MAPP PSS/E models 2007 series models:



Study will investigate new 115kV breaker configuration and local contingencies only. Study parameters will be adjusted to include the preceding projects identified by the ISDs within the generation queue.


Page 73

The maximum power export from Manitoba to the US is 2175 MW. Transfers to the US will be maximized based on available accredited generation above native load, allowing for spinning reserve.

b. Transient stability analysis

2007 series MAPP models:

2012 and 2017 summer off peak with maximum (725 MW) Winnipeg River generation.

2. Transient stability analysis The following NERC category B (single component) and C (multiple components) disturbances will be tested to determine the impact on transfer capability and overall system stability within Manitoba using the 2012 summer-peak stability model:

iii. 3-phase normal clearing faults with system intact iv. Single line to ground stuck breaker (slow clearing) faults with

system intact

4. Interconnection System and Network Upgrades Solutions to any limitations discovered during steady-state post-

disturbance and transient stability analysis will be determined. 5. Short Circuit Analysis Short Circuit Analysis is required to asses any increased short circuit levels on proposed new breaker layout. Three phase and single-line-to-ground fault levels will be calculated with PSS/E.


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APPENDIX B: Correspondence


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APPENDIX C :

MRO Model Single Line


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Page 77

APPENDIX C : MRO Study Case Single Line Diagram


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Documents

: Correspondence 74 - OATI · PDF fileAPPENDIX C: MRO Study Case Single Line Diagram ... supplier does not supply the IEEE PSS2A. The PSS2B has a third lead/lag block which may be