System Impact Study Report

Transcription

1 System Impact Study Report for Transmission Service Request # July 2005 Prepared By: G.R.Belanger Supervisor Grid Development Submitted By: G.R.Belanger Supervisor Grid Development Approved By: A.C.Thomson Manager Network Development Date: Date: Date:

2 2 Purpose This study was required to assess the impact of OASIS transmission service request #699453, as per Section 15.2 of SaskPower s OATT. POR SPC POD WAUW Service Requested 150 MW, firm Period 2008 to 2028 SaskPower OASIS Interface SPC-WAUW Objective To assess the interconnection options and associated costs. To assess the impact that OASIS transmission service request # 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 kv transformer capacity in 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 1 st order contingencies studied). Prior transmission facility outages (only system intact cases studied).

3 3 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 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. 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.

4 4 Interface Schedule TRM Transfer Modeled MHEB SPC 0 & 105 MW 45 MW 0 & 150 MW PPOA - SPC -150&54 MW 0 MW -150 & 54 MW WAUE SPC 0 & 150 MW 15 MW 0 & 165 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 either having all lignite fired units at highest dispatch priority (full lignite dispatch) or all hydro units at highest dispatch priority (high hydro dispatch). These generation dispatch patterns result in the highest potential transmission system loading for critical lines. 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 were as follows: 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 B1Q 230 kv line trip C2Q 230 kv line trip C1S 230 kv line trip C3B 230 kv line trip E2B 230 kv line trip P52E 230 kv line trip R7B 230 kv line trip R25Y 230 kv line trip C1B 230 kv line trip C1W 230 kv line trip C2B 230 kv line trip C1W 138 kv line trip B1W 138 kv line trip C1P 138 kv line trip P1H 138 kv line trip P1S 138 kv line trip R2C 138 kv line trip W1Y 138 kv line trip Also, the assessment considered the Centennial Wind Farm at both full output (150 MW) and at zero output.

5 5 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 series winter peak and summer peak cases. These cases assume all available transmission facilities are inservice. 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: 150 MW of load was added at the Poplar River 230 kv bus to represent the requested transfer. 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" and "high hydro" conditions. Worst case transfers were modeled on all interfaces. Including a previously queued for 54 MW, firm, from the PPOA. Poplar River unit #2 (PR#2) is modeled at 315 MW (as per a previously queued interconnection request). Boundary Dam unit #6 (BD#6) is modeled at 299 MW (as per a previously queued interconnection request). CCILS mitigation is included. 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.

6 6 Interconnection Facilities To accommodate this transmission request, interconnection facilities would be required, on the Saskatchewan side of the interface. Based on WAPA studies, these facilities would include a new HVDC converter, a connection from the new converter to the Poplar River Switching Station 230 kv bus, and associated CP&C equipment. A section of 230 kv transmission line from the converter to the US border would also be required, and are included in the corresponding WAPA study for this request. The single line diagram in Figure 1 shows the proposed general configuration. Figure 1 Proposed General Configuration Converter Station Approx. 16 km. 230 kv AC-DC-AC Converter (150 MW) < 1 km 230 kv To Poplar River Saskatchewan/Montana Boarder To Montana The proposed bus connection at the Poplar River Switching Station is shown in Figure 2. Figure 2 Existing Configuration and Proposed Poplar River Switching Station Bus Connection. Existing Configuration P2C Proposed Connection P2C To Converter P2A P2A PR#1 901T PR#2 902T 906T 907T Station Service PR#2 902T 906T 907T Station Service Not to scale PR#1 901T Not to scale

7 7 Interconnection Facility Costs Poplar River Switching Station cost = $3,367,500 Poplar River to Converter ( 1 km) 230 kv line cost = $321,000 Converter station site (land, levelling, and fence costs) = $214,500 CP&C costs = $909, Total ($2008) = $4,812,000 Note: These costs do not include any facilities outside Saskatchewan, any HVDC converter station or associated facilities or the transmission line costs from the converter to the USA boarder. These costs were to be included in the studies done by WAPA. These costs would be confirmed as part of the facility study. 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 Table 1, below, shows the loading on monitored lines under heaviest loading conditions, with and without the requested service. Table 1: Effect of 150 MW Load Increase at Poplar River on the Maximum Flows for Monitored SaskPower Transmission Lines (Without Centennial Project). Maximum Line Flows (in MVA) Line Without 150 MW Poplar River Load Increase With 150 MW Poplar River Load Increase Summer Winter Summer Winter A1P A1S B1W-W B2W-B B3P B3R C1S C1W P2A P2C P3C Q1W-Q R1P-R R5B S2P The shaded cells the tables indicate lines that have a maximum loading that is higher with the requested transmission service, compared to without the service.

8 8 The results show most lines have reduced loading with the requested service, and that the loading increases are small for the lines with higher loading. These higher loading conditions would not be expected to result in any new vertical clearance violations. Table 2, below, includes the effect of the Centennial Wind Farm. Table 2: Effect of 150 MW Load Increase at Poplar River on the Maximum Flows for Monitored SaskPower Transmission Lines (With Centennial Project). Maximum Line Flows (in MVA) Line Without 150 MW Poplar River Load Increase With 150 MW Poplar River Load Increase Summer Winter Summer Winter A1P A1S B1W-W B2W-B B3P B3R C1S C1W P2A P2C P3C Q1W-Q R1P-R R5B S2P The results in Table 2 show that the Centennial wind farm would not materially affect the impact of this request. First Swing Stability Because transmission loading is reduced with the requested service, no cases of unit instability would be expected to occur as a result of this transmission service. Transient Period Voltages New violations were not expected to occur for the cases studied, with the requested transmission service. Loss Benefits The preliminary loss calculations, associated with this service request, indicate that the loss benefits would range from approximately 9% for a 150 MW, to 11% for a 50 MW transfer. These results assume that additional generation at QE is brought on, corresponding to the transfer level. If SaskPower resources are dispatched economically, rather than bringing on new generation only at QE, the loss benefits would be different. These benefits would also depend on future generation developments.

9 9 These loss benefits would be confirmed as part of the facility study. Conclusions To facilitate this transmission service request (#699453), new transmission interconnection facilities would be required. These interconnection facilities would consist of: Approximately 1 km of 230 kv transmission line. Termination facilities at the Poplar River Switching Station. Protection and associated communication and control facilities. The preliminary cost of the interconnection facilities would be approximately $4.8M ($2008), and would typically require a minimum of two years of lead-time, from the approval date. The requested service would result in lower transmission losses on the SaskPower system. A facility Study would be required to optimize the design and confirm the costs and loss benefits. This transmission service request (#699453) is not expected to result in impacts on the SaskPower transmission system that will result in a violation of system performance or reliability criteria. Accordingly, no other network upgrades are required.

10 Appendix A SaskPower Transmission Facilities Diagram 10

11 60 WELLINGTON WATERLOO CHARLOT URANIUM CITY NORTHWEST TERRITORIES SASKATCHEWAN Lake At habasca Wollast on Lake Reindeer Lake KINOOSAO ALBERTA SASKATCHEWAN MANITOBA SASKATCHEWAN 56 Churchill Lake C h u r c h i l l 56 Pet er Pond Lake R i v e r C H URCHI L L RIV E R Lac La Ronge ISLAND FALLS FLIN FLON River Beaver 54 Nort h MEADOW LAKE E.B. CAMPBELL River 54 LLOYDMINSTER Sask at c PRINCE ALBERT Saskat chewan BATTLEFORD SASKATCHEWAN 108 NORTH BATTLEFORD 52 C3B 52 MAPLE CREEK hewan NIPAWIN E2C/E2B C1B C2B/E2B P52E S1M LANDIS HYDRO GENERATING SITE THERMAL GENERATING SITE ROSETOWN KINDERSLEY SUCCESS SW7 River COTEAU CREEK C1S Lake Diefenbaker SWIFT CURRENT Sout h A1S Chaplin Saskat chewan GRAVELBOURG SASKATOON 106 er Riv QUEEN ELIZABETH (DUAL FUELS) Hawarden C1P P1S P1H P2A POPLAR RIVER B1Q/B2Q Pasqua C2Q ASSINIBOIA INTERNAL COMBUSTION GENERATING SITE J: \ WORKGRP\ LIBRARY\ PROTO\ FACMAP FEBRUARY / 2000 QU'Appelle A1P R1P/R5B P2C MONTANA C1W MELFORT River REGINA W1Y W1R WEYBURN P2C BOUNDARY DAM MELVILLE B2R/B3R B2W YORKTON ESTEVAN SHAND MOOSOMIN NORTH DAKOTA kv TRANSMISSION LINES 138 kv TRANSMISSION LINES TIE LINES S2P B1K R25Y R7B 50

12 Appendix B Relevant Transmission Plans 12

13 13 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: 2008

14 14 Regina kv Transformer Capacity Increase Background Following the failure of one of the kv transformers at the Regina South switching station, the remaining 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 Add kv transformer capacity at the Regina South switching station with new higher rated transformers or an additional transformer. Replace one 138 kv breaker (<1000 Amp margin). In-service Date: 2007