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SaskPower

Facilities Study Report

OASIS Request #617667

January 2003

Prepared By:Network Development Department

SaskPower

1. Introduction

The System Impact Study for OASIS request # 558643 concluded that network upgrades would be required to facilitate a 35MW increase in the firm transfer capability on the PPOA interface. Subsequently, OASIS request # 617667 was submitted to initiate an associated Facilities Study.

Transfer capacity requested = 35 MW

POR = QEPS

POD = PPOA

Original Requested Service Date = October, 2002 - October 2004.

This report documents the results of the Facilities Study pertaining to SaskPower OASIS request #617667, and identifies required facility upgrades to SaskPower’s transmission network. An estimate of the cost and completion date is also provided.

2. Scope

The results of this study include an analysis of the steady state thermal and voltage impacts on primary grid transmission facilities (transmission lines and transformers) in the SaskPower system, due to the associated transmission service request.

This study considers:

  • The steady state impact of a 35 MW increase in the firm transfer level to the PPOA. Including:
  • Pre-contingency facility thermal overloading or voltage violations.
  • Post-contingency facility thermal overloading or voltage violations, including automatic system adjustments.
  • Post-contingency facility thermal overloading or voltage violations, including manual system adjustments required to return ACE to within deadband.
  • Pre-contingency operating conditions on the existing system that produce the highest loading on equipment by considering:
  • Seasonal load levels,
  • Potential generation patterns,
  • Approved interface transfer levels.
  • Planned future system modifications or additions to primary facilities or operations.
  • Previously queued requests for interconnection studies and transmission service.

This Study does not consider:

  • The impacts on facilities outside of the SaskPower System.
  • Transient stability (historical limits have been based primarily on steady state limiting conditions).
  • Higher order contingencies (only 1st order contingencies studied).
  • Prior Equipment outages (only system intact cases studied).

3. Study Methodology

The system simulations, for the study, were conducted using the PSS/E software package[1]. Only steady state simulations were conducted.

This assessment assumes that the existing CCILS (Coteau Creek Initiated Load Shed) scheme will be phased out in SaskPower's transmission development plans. However, internal studies are still in progress and approvals have not yet been obtained to proceed with any facilities associated with CCILS mitigation. For this reason, the results of this study are contingent on receiving approval to proceed with construction of facilities for CCILS mitigation. At this time, those facilities tentatively include a Static Var System (SVS) located at the Pasqua Switching Station, increases to the vertical line clearance on several transmission lines and possibly new 230-138 kV transformation capacity at Regina. If clearances cannot be adequately increased, new transmission lines may be required, or transfer capabilities reduced.

For the steady state assessment, all lignite (southern) generation is fully dispatched and maximum east to west and south to north firm transfer levels modeled at all interfaces. Various seasonal load levels are included in the assessment to represent a cross section of operating conditions.

The simulations are intended to identify worst case (maximum) transmission loading scenarios to ensure system performance is not unacceptably degraded and that equipment capability is adequate under all probable operating conditions. The simulations for the base case conditions are compared to cases that include the requested transfer. The steady state performance of the SaskPower system, prior to, and following first order contingencies are assessed to determine if the impacts within the SaskPower system are:

  • within acceptable operating limits for equipment (voltage and reactive power loading).
  • within acceptable thermal loading capability of equipment,

The first order contingencies included in this assessment include:

  • P2A 230 kV line trip with Poplar River #2 unit crosstripped (P2A-Xtrip)
  • P2C 230 kV line trip with Poplar River #2 unit crosstripped (P2C-Xtrip)
  • PR1 generating unit trip
  • B3R 230 kV line trip
  • A1S 230 kV line trip
  • C1S 230 kV line trip
  • C2Q 230 kV line trip

Prior equipment outages or higher order contingencies were not considered.

4. Base Case Development

For all steady-state simulations, the cases were based on a modified MAPP[2] 2000 series winter peak cases and modified MAPP 2000 series summer peak case. These cases assume all available transmission facilities are in-service. The winter cases having higher loads with a slightly different loading pattern, compared to summer cases. Also, generator and transmission facility capabilities vary between winter and summer cases.

The following changes were made to the cases for use in this analysis:

  • Load levels were scaled to produce the following study cases.
  • Summer off-peak/Winter off-peak (1900, 2150 and 2300 MW load levels)
  • Summer peak/Winter off-peak (2500 and 2700 MW load level)
  • Winter peak (2900 MW load level).
  • Generation was re-dispatched in all study cases to reflect "full lignite" (all coal fired generation dispatched) with two Meridian and two Cory units designated as must run. IMC and Weyerhaeuser self-generation units were assumed to be on-line.
  • Transfers at existing firm Available Transfer Capability (ATC) limits were modeled on all interfaces to capture worst case loading conditions, for all cases. These include:
  • 165 MW north ATC on the USA interface (WAPA).
  • 105 MW west ATC on the Manitoba 230 kV interface (MHEB).
  • 15 MW west ATC on the Alberta interface (PPOA).
  • Future SVS (Static Var System) was added at the Pasqua 138 kV bus for CCILS (Coteau Creek Load Shed) scheme mitigation. The tentative in-service date for these mitigation facilities is December 2005.
  • Future generation (155 MW) was modeled at the Pasqua 138 kV bus to represent an interconnection request (TI-2), that was queued after this request (2004 in-service date), for comparison purposes. The 155 MW of new generation associated with this request was modeled as synchronous with a minimum of 0.90 power factor capability (overexcited), in all cases.

5 Study Results

5.1 Voltage and Reactive Power Analysis

The study results showed that the 35 MW increase in PPOA transfer level would require additional reactive support in the SaskPower system. This support is necessary to prevent Estevan area generators from reaching reactive power limits following contingencies, resulting in associated system voltage instability.

The addition of a 40 MVAr (minimum) switched capacitor bank at the Peebles Switching Station would prevent the voltage instability condition (return reactive loading to base case levels). The capacitor would be switched in (mechanically) if grid voltage levels decayed below a set trigger level.

5.2 Thermal Loading Analysis

The assessment of thermal loading was limited mainly to primary facilities (transmission lines and transformers). There may be other associated unidentified equipment that could be limiting such as wavetraps and switches, however, this equipment is usually relatively low cost compared with the estimation error (plus or minus 30%).

5.2.1 Steady State Pre-Contingency Primary Equipment Loading

These steady state results are intended to identify heavy pre-contingency power flow conditions that would violate operating limits. These conditions assume all transmission facilities are available, prior to a contingency event occurring.

The steady state pre-contingency results are summarized in Table 1, for circuits that were significantly impacted by the transmission service request.

No steady state pre-contingency operating limit violations are expected to occur, as a result of the requested service.

Table 1 Maximum Pre-contingency Line Loading
TI-2 / C1S / P1S / A1P / R1P / B2R / C1P / QE 906T / RE 903T
Generator / Line Flow / Line Flow / Line Flow / Line Flow / Line Flow / Line Flow / Transformer / Transformer
Status / Summer/Winter / Summer/Winter / Summer/Winter / Summer/Winter / Summer/Winter / Summer/Winter / Summer/Winter / Summer/Winter
(MVA) / (MVA) / (MVA) / (MVA) / (MVA) / (MVA) / (MVA) / (MVA)
*Rating / 237/239 / 101/155 / 126/194 / 126/179 / 425/425 / 126/179 / 250/288 / 207/239
Base / off-line / 120/120 / 22/28 / 64/60 / 95/96 / 292/277 / 60/63 / 207/204 / 169/161
Base / on-line / 133/134 / 35/41 / 44/40 / 49/52 / 281/265 / 82/87 / 217/214 / 145/139
Additional 35 MW to PPOA / off-line / 104/104 / 27/32 / 61/58 / 98/99 / 294/278 / 59/62 / 199/199 / 170/163
Additional 35 MW to PPOA / on-line / 120/115 / 39/45 / 41/37 / 56/57 / 283/268 / 84/83 / 210/221 / 146/141

* Transmission lines limited by minimum allowable vertical clearances (sag).

5.5.2 Steady State Post-Contingency Primary Equipment Loading

These steady state results are intended to identify heavy post-contingency power flow conditions that would violate operating limits. These conditions assume all transmission facilities are available, following the occurrence of a contingency event. These simulation results represent the system conditions several minutes after the contingency, when all automatic control action has occurred (voltage dependant load restored) with the exception of automatic generation control. No manual operator action is considered.

The steady state post-contingency results are summarized in Table 2. The shaded areas of the tables indicate power flow levels above rating (potential violations). Also, since voltages can be below nominal in some post-contingency cases, corresponding equipment ratings may have a proportionally lower MVA value that is not represented in the tables.

Table 2 Maximum Post-contingency Area Line Loading
TI-2 / C1S / P1S / A1P / R1P / B2R / C1P / QE 906T / RE 903T
Generator / Line Flow / Line Flow / Line Flow / Line Flow / Line Flow / Line Flow / Transformer / Transformer
Status / Summer/Winter / Summer/Winter / Summer/Winter / Summer/Winter / Summer/Winter / Summer/Winter / Summer/Winter / Summer/Winter
(MVA) / (MVA) / (MVA) / (MVA) / (MVA) / (MVA) / (MVA) / (MVA)
*Rating / 237/239 / 101/155 / 126/194 / 126/179 / 425/425 / 126/179 / 250/288 / 207/239
Base / off-line / 157/157 / 95/103 / 164/161 / 221/226 / 444/419 / 99/103 / 262/261 / 248/244
Base / on-line / 170/171 / 110/119 / 146/146 / 167/177 / 426/399 / 124/132 / 273/284 / 222/219
Additional 35 MW to PPOA / off-line / 144/161 / 105/112 / 167/165 / 228/235 / 446/421 / 101/104 / 258/260 / 252/248
Additional 35 MW to PPOA / on-line / 157/157 / 122/130 / 151/149 / 180/186 / 430/405 / 130/133 / 283/284 / 226/224

* Transmission lines limited by minimum allowable vertical clearances (sag).

The results in Table 2 show that the P1S, A1P, R1P (and parallel R5B line), B2R/B3R lines and the QE906T (QE 230-138 kV) and RE903T (Regina 230-138 kV) transformers are overloaded in the base case (shaded cells are overloads). With the requested transmission service added, these overloads are only slightly higher.

For R1P/R5B and RE903T overloads, the limiting contingency involves loss of significant generation. The deployment of contingency reserves would significantly reduce loading on those circuits within 15 minutes. Even with deployment of the reserves, loading may still exceed rating on R1P/R5B (vertical clearance limit). To address this condition it would be necessary to increase the vertical clearance. If this is not possible, a new transmission circuit will be required, between the Pasqua and Regina (or Condie) stations.

For the QE906T overload, the transformer would still be within its short-term rating (currently set at approximately 10% above its rating). After the overload occurs, operators would be required to restore the tripped transmission line or manually re-dispatch generation to reduce the QE906T transformer loading.

For the P1S, A1P and B2R/B3R transmission lines, it will also be necessary to increase vertical clearances to avoid rating violations during contingencies.

6. Facilities Costs

A cost estimate for the Peebles capacitor is included in Appendix B. No costs for the uprating of overloaded circuits was provided since this mitigation is required primarily for the existing system.

7. Schedule

The tentative schedule for CCILS mitigation is for completion by December of 2005. However, if new transmission lines are required, as part of the CCILS mitigation, the schedule will need to be re-assessed. The schedule for the completion of the Peebles capacitor addition would be coincident with the CCILS mitigation project schedule.

8. Conclusions

Providing the requested service is contingent upon SaskPower approval of the CCILS mitigation facilities. Studies for these facilities are currently in progress.

To avoid post-contingency steady state voltage instability additional new facilities would be required. These include a 40 MVAr mechanically switched capacitor bank (proposed location would be the Peebles Switching Station) and modifications to the McNeill runback control system (change from 15 to 50 MW).

The earliest completion schedule for the facilities is December, 2005. If new transmission lines are required (cannot increase ratings of existing lines), the schedule will need to be re-assessed.

The information presented in these studies is based on the specific study requests contained herein and is pursuant to SaskPower's OATT Section 19. Conclusions contained in these studies do not necessarily apply to any other request that may be presented to SaskPower. SaskPower reserves the right to offer a new study which may contain very different conclusions based on new request information. SaskPower does not accept responsibility for any loss or damage occasioned by the use of this information by the user or any third party for any other purpose other than the original study request including any direct, special, coincidental, indirect or consequential damages, including lost profits and savings, or any other damages whatsoever. Any questions should be directed to

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Appendix A

Interconnection Single Line Diagrams



Appendix B

Facilities Cost Estimate

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Cost Summary - Peebles Capacitor Addition

Station Costs

Add 40 MVAr, 138 kV capacitor bank at$1,722,000

the Peebles Switching Station.

CP&C Costs

Protection.$56,000

Communications facilities.$0

SCADA$14,600

Modifications to McNeill Runback$20,000

To change from 15 to 50 MW

(generic estimate)

Total (2004$)$1,812,600

[1] PSS/E is a software package by Power Technologies Incorporated (PTI). It is widely used by power utilities to perform steady-state, transient, and dynamic simulation of power system operation.

[2] Mid-continent Area Power Pool (MAPP) is a voluntary association of electric utilities that acts to regulate the reliability, the accessibility, and the marketing of the bulk electric system of the Upper MidWest Power Region.