System Impact Study

SaskPower

System Impact Study

for

OASIS Request #70084446

September 2003

Prepared by:G.R.Belanger

Grid Development

Network Development Department

SaskPower

Purpose

This study was required to assess the impact of OASIS transmission service request #70084446, as per Section 15.2 of SaskPower’s OATT.

POR – NIHS

POD – MH.230

Service Requested – 200 MW, Firm

Period – December 1, 2003 – January 1, 2005

SaskPower OASIS Interface –SPC-MH.230

Objective

• To assess the steady state impact that OASIS transmission service request #70084446 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 SVS (approximately 200 MVAr), 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.

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,
• Reactive power loading on generators.
• Generator stability and transient voltage recovery.

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 prior transfers shown below, to represent worse case conditions. The transfers modeled include TRM values to account for the control deadbands on these interfaces.

Interface Schedule TRMWorst CaseTransfer Modeled

SPC – MHEB 54 MW 45 MW 99 MW

SPC - PPOA -75 MW 0 MW -75 MW

SPC – WAUE -50 MW -15 MW -65 MW

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

The worst case generation patterns, for assessing the requested transmission service, would be represented by having all lignite fired units at maximum output (full lignite dispatch) and a full hydro dispatch (lignite off-line). These 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 200 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
• P52E 230 kV line trip
• R7B 230 kV line trip
• 200 MW generation trip in Manitoba
• B2R 230 kV line trip
• B2Q 230 kV line trip
• C2Q 230 kV line trip
• C3B 230 kV line trip
• C1S 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 and summer peak and off-peak cases. These cases assume all available transmission facilities are in-service, unless noted. 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 study cases to reflect "high lignite" (all lignite coal fired generation dispatched at maximum output).
• Generation was re-dispatched in study cases to reflect "high hydro" (all hydro generation dispatched at maximum output and BD#6 and Shand off-line).
• Worst case transfers were modeled on all interfaces.
• Poplar River unit #2 (PR#2) is modeled at 330 MW (as per a previously queued interconnection request (Queue # TI-9) 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 (Queue # TI-5) for a 6 MW increase in unit output).
• A generator is modeled at 185 MW in all cases and is connected directly into the Pasqua 138 kV bus, via a new radial 138 kV transmission line. This is associated with a previously queued interconnection request (Queue # TI-2).
• CCILS mitigation is included (see Appendix B).

Summary of Study Results

The following potential impacts were associated with this request:

• Post contingency line overloading.

Post Contingency Overloads

There are several 230 kV line contingencies that can result in high flows on other 230 kV equipment and on the underlying 138 kV system. Specifically, high loading can occur on the R7B line following a B2R or B3R line trip (high lignite scenario) and high loading can occur on the B1W line following a P52E line trip (high hydro scenario).

Table 1 below shows the loading on lines under heaviest loading conditions, with and without the requested service. These conditions include a high lignite and high hydro dispatch for a summer off-peak load scenario. The results also include cases to illustrate the sensitivity to the 185 MW, previously queued interconnection request (Queue # TI-2).

The shaded cells in Table 1 indicate overloading conditions. With this transmission service request (#70084446), the existing R7B 230 kV line will be overloaded after B2R or B3R line trips, under high lignite conditions. Also, the loading on the B1W circuit will be overloaded following a P52E 230 kV line trip, under high hydro conditions.

First Swing Stability

Although higher transfers reduce margins, no cases of instability resulted, due to this service request.

Transient Period Voltages

No new violations were identified for the cases studied.

Conclusions

The transmission service request #70084446 will result in impacts on the SaskPower transmission system that violate the study criteria. Specifically, unacceptable loading on the R7B and B1W lines results, following 230 kV line contingencies.

As identified in Table 1, partial service would be available. This partial service would be 95 MW if previously queued requests are not considered (140MW - 45MW = 95 MW).

This partial service would be 0 MW if previously queued requests are considered.

To facilitate this transmission service request, in full, new transmission facilities would be required or existing facilities would require upgrading.

• New facilities would consist of new transmission lines with high associated costs.
• Upgrading would consist of increasing vertical clearances on the R7B and B1W lines, if possible. In order to determine the cost of this mitigation, a detailed line assessment would be required. The cost of this assessment would be approximately $250,000 per line. Mitigation costs would depend on the results of the assessment. There would be additional costs associated with assessment and mitigation on the Manitoba Hydro portion on R7B.

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 (approximately 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.