SaskPower

System Impact Study

for

OASIS Request #701021

July 12, 2003

Prepared by:Grid Development

Network Development Department

SaskPower

Purpose

This study was required to assess the impact of OASIS transmission service request #701021, as per Section 15.2 of SaskPower’s OATT.

POR – WAUE

POD – SPC

Service Requested – 100 MW, firm

Period – July 1, 2003 – July 1, 2004

SaskPower OASIS Interface – SPC-WAUE

Objective

  • To assess the impact that OASIS transmission service request #701021 would have on the SaskPower transmission system.
  • To determine if the impacts are acceptable.
  • To determine if a level of partial service is available, if the impacts are not acceptable.
  • To identify mitigation options, if the impacts are not acceptable.

Scope

This study considers:

  • The applicable term of the request.
  • The basecase loadflow cases consistent with those included in SaskPower’s year 2003 data submission to MAPP.
  • The worst case SaskPower winter and summer load and generation scenarios.
  • Applicable planned future system modifications or additions to the SaskPower transmission system (see Appendix B for additional planning information).
  • Mitigation of the Coteau Creek Initiated Load Shed Scheme (CCILS) for N-1 contingencies. This includes the addition of a 200 MVAr SVS, in 2005, at the Pasqua Station and up-rating of circuits in the Pasqua area to allow for higher post-contingency flows.
  • Increased Regina South 230-138 kV transformer capacity in 2005.
  • Previously queued requests for interconnection studies and reserved transmission service that produce the worst case conditions.
  • Any applicable previous study work.

This Study does not consider:

  • The impacts on facilities outside of the SaskPower System.
  • Higher order contingencies (only 1st order contingencies studied).
  • Prior transmission facility outages (only system intact cases studied).

Study Criteria

For all long-term transmission requests, an N-1 contingency criteria was used in assessing the long-term system impacts. This criteria requires that, for an N-1 contingency, the transmission system must remain stable with all equipment within ratings, without shedding firm load or the cascade tripping of facilities. Stability margins are based on MAPP System Design Standards and Operating Studies Manual.

Study Methodology

The system simulations for assessing the system impacts for this study were conducted using the PSS/E software package[1]. These simulations form the basis for the impact study conclusions.

Because this request is for long-term firm transmission service, the system impacts must be evaluated considering the potential for the customer to exercise "roll over rights". For this reason, this study assessment includes the effects of future planned transmission system modifications and additions, and planned load growth, beyond the requested service period.

SaskPower has existing plans, in 2005, to add facilities to offset the dependence on the CCILS scheme for N-1 contingencies, as described in Appendix B. As a result of these modifications, transfer levels within the SaskPower system may be limited under specific conditions.

This study examines the performance of the SaskPower system, prior to, and following N-1 contingencies, to determine the impact on:

  • Thermal loading of equipment,
  • Operating limits of equipment,
  • System steady state voltage stability,
  • System dynamic stability,
  • Reactive power loading on generators.

The simulations are intended to represent worst case generation and loading scenarios to ensure pre and post contingency system performance is not unacceptably degraded and that equipment capability is adequate under all possible normal operating conditions.

Based on reserved schedules and previously queued requests, the interfaces were modeled with the simultaneous transfers shown below, to represent worse case conditions. The transfers modeled include TRM values to account for the control deadbands on these interfaces.

InterfaceScheduleTRMTransfer Modeled

MHEB – SPC105 MW 45 MW 150 MW

SPC - PPOA 50 MW 0 MW 50 MW

WAUE – SPC 50 MW15 MW 65 MW

These interface transfers result in the worst case system conditions (highest potential transmission system loading), required for assessing the requested long term firm transmission service.

The worst case generation pattern, for assessing the requested transmission service, would be represented by having all lignite fired units at maximum output (full lignite dispatch). This generation dispatch results in the highest potential transmission system loading for critical lines.

The worst case loading conditions, for assessing the requested transmission service, would be an off-peak scenario where load tracking northern hydro generation is at minimum output and southern lignite units base loaded at maximum. For this study, the cases representing summer and winter load levels were scaled (in 50 MW increments) to consider the full range of operation and future load growth.

The worst case first order contingencies included in this assessment include a:

  • 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
  • A1S 230 kV line trip
  • B2R 230 kV line trip
  • B2Q 230 kV line trip
  • C2Q 230 kV line trip

The SaskPower transmission facilities diagram in Appendix A shows the transmission lines.

System performance was also considered with one Poplar River unit off line during maintenance, however this case did not represent a more onerous condition.

Base Case Development

Base case development is intended to produce simulations that represent a heavily stressed system boundary condition. This is necessary to ensure that potential operating security violations and associated mitigation requirements are identified.

For all simulations, the cases were based on modified MAPP[2] 2003 series winter peak and summer peak cases. These cases assume all available transmission facilities are in-service. The winter cases have higher peak loads with a slightly different loading pattern, compared to summer cases. Also, generator and transmission facility capabilities may vary between winter and summer cases.

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

  • Cases were equivalenced to reduce the computational requirements for the steady state studies. The equivalenced cases retained the full SaskPower, Manitoba Hydro and Northern MAPP data representation.
  • Load levels were scaled to produce summer and winter cases for the full range of operation.
  • Generation was re-dispatched in all study cases to reflect "full lignite" (all lignite coal fired generation dispatched at maximum output).
  • Worst case transfers were modeled on all interfaces. Including a previously queued for 35 MW, firm, to the PPOA (existing firm is 15 MW)
  • Poplar River unit #2 (PR#2) is modeled at 330 MW (as per a previously queued interconnection request for a 25 MW increase in unit output).
  • Boundary Dam unit #6 (BD#6) is modeled at 299 MW (as per a previously queued interconnection request for a 6 MW increase in unit output).
  • CCILS mitigation is included.

Summary of Study Results

The following potential impacts were associated with this request:

  • Post contingency line overloading.
  • First swing stability for the Boundary Dam units for close in 3 phase faults.
  • Transient period voltage violations for close in 3 phase faults at Boundary Dam.

Post Contingency Overloads

Without the CCILS scheme, the worst case post contingency loading result from a P2A-Xtrip event. This event includes the loss of the P2A 230 kV transmission circuit and the subsequent intentional crosstrip of a 305 MW Poplar River generator (PR#2). The loss of the generating unit results in high flows over the US and MH tie lines and transmission within the SaskPower system. The loss of the 230kV line results in a further increase in flows on the underlying SaskPower 138 kV system. This can cause overloading on the 138 kV lines between the Regina South and Pasqua Stations, and potential vertical clearance violations.

Without the CCILS, the trip of the A1S 230 kV transmission line can also result in high flows on the underlying 138 kV system. Specifically, high loading can occur on the P1S, C1P/C1H and A1P lines, terminating at the Pasqua switching station.

SaskPower has authorized funds to assess and up-rate the lines terminating at the Pasqua Station, to prevent post contingency vertical clearance violations from occurring. If increases to the vertical clearances are required, the tension of the lines will have to be increased. Ideally, this re-tensioning would allow emergency operation up to the maximum allowable conductor temperature (100 degrees C ).

However, even considering re-tensioning to 100 degrees C, the R1P and R5B/B6P 138 kV lines can still become overloaded in summer. This condition is exacerbated by the requested transmission service.

Table 1 below shows the loading on the Pasqua lines under heaviest loading conditions, with and without the requested service. These conditions include a full lignite dispatch for a summer off-peak load scenario. The results also include cases to illustrate the sensitivity to previously queued requests.

Table 1 Post-contingency Pasqua Area Line Loading - Post CCILS Mitigation
New 138 kV line from / System
gross / MHEB to SPC / WAUE to SPC / SPC to PPOA / R1P
R5B/B6P / P1S** / A1P** / C1P/P1H**
Case / Regina to / load / Transfer / Transfer / Transfer / Line Flow / Line Flow / Line Flow / Line Flow
Pasqua / (MW) / (MW) / (MW) / (MW) / (MVA) / (MVA) / (MVA) / (MVA)
* Rating / 166 / 133 / 166 / 166
Summer off-peak load / No / 2100 / 150 / 65 / 15 / 212 / 95 / 175 / 98
Summer off-peak load Without PR#2 and BD#6 increases / No / 2100 / 150 / 65 / 15 / 211 / 94 / 169 / 98
Summer off-peak load / No / 2100 / 150 / 65 / 50 / 224 / 105 / 179 / 103
Summer off-peak load Without PR#2 and BD#6 increases / No / 2050 / 150 / 65 / 50 / 219 / 104 / 172 / 101
Summer off-peak load / No / 2200 / 150 / 165 / 15 / 231 / 101 / 179 / 106
Summer off-peak load Without PR#2 and BD#6 increases / No / 2200 / 150 / 165 / 15 / 225 / 98 / 172 / 102
Summer off-peak load / No / 2200 / 150 / 165 / 50 / 240 / 110 / 182 / 109
Summer off-peak load Without PR#2 and BD#6 increases / No / 2150 / 150 / 165 / 50 / 237 / 109 / 176 / 107
Summer off-peak load / Yes / 2200 / 150 / 165 / 50 / 164 / 113 / 170 / 114
Summer off-peak load Without PR#2 and BD#6 increases / Yes / 2150 / 150 / 165 / 50 / 163 / 113 / 164 / 115
* These ratings are based on successful re-tensioning of these lines to allow 100 degree C operation at 40 degrees C ambient.
** The maximum P1S, A1P, C1P and P1H loading occurs for an A1S 230 kV line trip.

The shaded cells in Table 1 indicate overloading conditions. With the new 138 kV line from Regina South to Pasqua in, the heavy R1P and R5B overloads are eliminated.

The results show where the A1P line may be overloaded by a small amount until the automatic generation control (AGC) system compensated for the higher losses. This condition should not result in a vertical clearance violation on A1P (considering a 100 degrees C operating capability for the line and a thermal time constant of 15 minutes).

The P52E, 230 kV transmission line loading was noted to be high for the P2A-Xtrip contingencies. Although these loading levels have not yet been flagged in Manitoba Hydro/SaskPower joint operating studies, it is possible that line upgrades would be necessary on the Manitoba section of the line, once this issue is investigated.

First Swing Stability

Although higher transfers reduce margins, no cases of instability resulted, due to this service request, with the additional 138 kV circuit between the Regina South and Pasqua stations.

Transient Period Voltages

Under extreme transfer conditions, the Weyburn 138 kV bus can experience transient period voltages slightly below the 0.70 pu limit, however, new violations were not identified for the cases studied with the new 138 kV line from Regina South to the Pasqua station.

Conclusions

The transmission service request #701021 will result in impacts on the SaskPower transmission system that violate the study criteria. Specifically, heavy loading on the underlying 138 kV system following 230 kV line contingencies, can cause line overloads and potential transient period voltage violations. No partial service would be available.

Although these impacts would not occur until after the term of the request, it is necessary to consider long term effects, to allow for possible roll over. After 2005, system modifications will have been made such that the CCILS scheme will not operate for N-1 contingencies. Without the CCILS scheme, this request will be constrained by limits within the SaskPower system.

Without the CCILS scheme, a re-dispatch of network resources may be required to prevent potential overload conditions, considering existing service commitments. It would not be possible to reliably implement further redispatch measures to facilitate higher firm transfer levels for new Point to Point requests.

To facilitate this transmission service request, new transmission facilities would be required to provide re-enforcement between the Regina South (or Condie) and the Pasqua Switching Stations. This re-enforcement would consist of:

  • Approximately 70 km of 138 kV transmission line.
  • Termination facilities at the Pasqua and Regina South (or Condie) Stations.
  • Protection and associated communication and control facilities.

This type of facility addition typically requires a minimum of two years of lead-time, from the approval date.

The estimated cost of this re-enforcement option would be approximately $17.9 million, which would include only a new Pasqua to Regina 138 kV line. This cost breakdown is shown in Table 2. Also, there may be additional costs to mitigate potential P52E overloading on the Manitoba Hydro section. The cost of this upgrade (if required), is not available (would have to be assessed by Manitoba Hydro).

A facility Study would be required to optimize the design and confirm the total costs.

Loss Benefits

The loss benefits associated with a new 138 kV transmission line from Pasqua to Regina, were not assessed.

Other Options

Other re-enforcement options such as line rebuilding or re-conductoring existing lines were not considered, since the cost of those options would approach the cost of a new 138 kV transmission line and would provide less system benefit.

Table 2 - Cost Breakdown for a new Pasqua to Regina 138 kV line

Add 138 kV Line from Pasqua Station to Regina South or Condie Station
2004 / 2005 / Total
70 km of 138 kV 3NNHS-2X Curlew / $3.40 / $10.85 / $14.25
Communications / $0.08 / $0.08
Protection / $0.13 / $0.13
Control / $0.78 / $0.78
Add Line Position at the Pasqua Station
2004 / 2005 / Total
Switching Station / $0.55 / $0.78 / $1.33
Add Line Position at the Regina South or Condie Station
2004 / 2005 / Total
Switching Station / $0.55 / $0.78 / $1.33
------
Total / $17.90
All costs are in millions of dollars

Appendix A

SaskPower Transmission Facilities Diagram


Appendix B

Relevant Transmission Plans

Coteau Creek Initiated Load Shed (CCILS) Scheme Mitigation

Background

Under high transmission loading conditions, some SaskPower contingencies can result in very high power flows on the underlying 138 kV system. This can result in potential overloading of some 138 kV lines (vertical clearance violations) and transformers. Due the associated higher reactive losses on these lines, it is possible that the Coteau Creek generator excitation systems may become overloaded and trip to manual control (these units do not have overexcitation limiters). On manual control, the reactive power output of the units would be reduced, potentially resulting in system undervoltage conditions and a risk of voltage collapse in the western part of the SaskPower system.

The CCILS scheme reduces post-contingency 138 kV line loading (and associated Coteau Creek reactive loading) by automatically tripping load at Swift Current, Moose Jaw, Saskatoon and North Battleford in three stages and running back (fast DC power reduction) non-firm transfers to Alberta. The CCILS is triggered by a high reactive power output condition at Coteau Creek that results in communications signals being sent to trip load stages until the reactive overload is relieved.

The scheme is designed such that under planned worst case conditions, only 2 of the 3 stages are required to operate for N-1 contingencies. This allows for a communication failure on one stage or for margin for unplanned conditions or modeling data variations.

Project Need

The CCILS scheme results in the shedding of firm SaskPower load for N-1 contingencies. This is not consistent with SaskPower’s long term plan to prevent load shedding for N-1 contingencies.

Project Description

  • Add reactive (200 MVAr) compensation at Moose Jaw (Pasqua Switching Station). This compensation would be a combination of continuously controlled (SVC) and fast switched capacitor banks.
  • Re-tension the existing 138 kV transmission lines in the Moose Jaw area for 100C operation.
  • Retrofit the Coteau Creek generating units to add OEL capability
  • Possible addition of a Special Protection System (SPS) to reduce post contingency overloads.

In-service Date: 2005

Regina 230-138 kV Transformer Capacity Increase

Background

Following the failure of one of the 230-138 kV transformers at the Regina South switching station, the remaining 230-138 kV transformer may be overloaded. These transformers are critical to ensuring the delivery of generation from the Boundary Dam area to the network.

Project Need

This project is required to maintain reliability for forecast firm load in the Regina area.

Project Description

  • Replace both 230-138 kV transformers at the Regina South switching station with new higher rated transformers and move the two existing units to Fleet Street.
  • Replace one 138 kV breaker (<1000 Amp margin).

In-service Date: 2005

[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.