SPP REPORT ON SEPTEMBER 7, 2000 TLR EVENT

Transcription

1 SPP REPORT ON SEPTEMBER 7, 2000 TLR EVENT On September 7, 2000, SPP initiated a TLR on the FtsXfrFtsXfr flow gate, #5017, that proceeded to the point of firm curtailments. In response to the reporting requirements contained in the May 30, 2000 draft Transmission Loading Relief Investigation Procedure document, SPP prepared a report on this event addressing thirteen bullet points associated with an initial investigation. The following is the report submitted by SPP for the September 7 FtsXfrFtsXfr TLR event addressing each of those points. 1. Description of purpose/cause of curtailment The purpose of the TLR initiated by SPP on September 7, 2000 was to relieve the Fort Smith 500/161 kv transformer (Monitored Element) of excessive east to west flows that would have resulted from an unexpected loss of the Fort Smith 500/345 kv transformer (Contingency Element). This facility is modeled as a flow gate labeled FtsXfrFtsXfr (flow gate # 5017) in the IDC for which an Outage Transfer Distribution Factor is calculated based on the loss of the Contingency Element. 2. Facility/flow gate limitations and flows at the time the TLR was initiated. The Monitored Element has an emergency rating of 480 MVA that is a short-term loadability factor for the 500/161 kv transformers. The post-contingency flow on the Monitored Element had reached 546 MW at the time the TLR Level 5 was initiated. 3. TLR levels, timing and relief requested amounts Attachment A contains the NERC TLR Log Report for the September 7 TLR event on the FtsXfrFtsXfr flow gate. All times are in CST. 4. Transmission and Generation outages or changes from prediction that may have contributed. Generation outages in the SPP region contributed to the abnormally high flows on the Monitored and Contingency Elements. Western Resources Wolf Creek (1163 MW) nuclear unit had just returned to service following a maintenance outage, but was capable of only minimal generation the afternoon of the TLR event. Western s Lawrence Energy Center Unit 5 was derated 200 MW to 194 MW. Both of these units are generally located west of the flowgate. 5. Procedures implemented prior to curtailment. Due to this flowgate being an interconnection between Entergy and OG&E, there was no redispatch option for OG&E since all their generation was west of the flow gate. The heavy flows were in an east to west direction. Reconfiguration of the transmission system was investigated, but it was decided that reconfiguration of the transformers at Ft. Smith was the only viable option. Unfortunately this was exactly the contingency that would create the overload on the flow gate. OG&E did allow pre-contingency

2 SPP Report on September 7, 2000 TLR Event loading to increase beyond a level that would have caused excessive post-contingency loading in an effort to ride through the situation without firm curtailments. 6. Complete Transaction Curtailment lists & comparison to IDC Transaction Lists both before and after curtailment. Attachment B contains the TLR Level 5 curtailment list issued by the IDC for relief on the FtsXfrFtsXfr flow gate on September 7. Please note that there was one approved MRD transaction initiated during this event. 7. Known transactions not in the IDC & actions taken. SPP assumed that all transactions were in the IDC and was not aware of any transactions flowing that were not in the IDC. 8. SCIS or other system messages No additional messaging for this TLR was posted other than that through the IDC. 9. State Estimator snapshots and security analysis including any contingency analysis or stability analysis along with any other recorded data indicating need for Transmission Loading Relief Attachment C shows a screen print of Flowgate Detail from the SPP EMS used to monitor current and anticipated flows on the SPP flowgates. This particular print was made just after the TLR Level 5 was issued and clearly indicates that the flow gate loading, 570 MW, was clearly beyond its emergency limit of 480 MW. The EMS time stamp of 16:27:03 is CDT. Results from other periodic analyses of pre-contingency and post-contingency flows from the EMS can be found in the NERC TLR Log Report in Attachment A. 10. ATC limitations before, during and after the TLR event. SPP did not observe any ATC limitations on the FtsXfrFtsXfr flow gate prior to September 7. During the event, no ATC on the FtsXfrFtsXfr flow gate was available. After the event, non-firm ATC for off-peak periods only was available. 11. Description of actions taken to avoid future curtailments Other than the expedited return to service of generators west of the flow gate, no actions were identified that would prevent future TLR events on the FtsXfrFtsXfr flow gate. For the period that the generators were expected to be out of service, SPP declined firm transmission service that affected the FtsXfrFtsXfr flow gate greater than 5%. 12. Re-dispatch actions taken. No redispatch action was taken until the TLR reached Level If firm transaction curtailment took place, description of Transactional Contribution Factor calculation and results as well as how necessary relief was obtained through network service and native load contribution. SPP used the TCF calculation process that has been recommended by the NERC Parallel Flow Task Force (PFTF) and endorsed by the Security Coordinator Subcommittee (SCS) and Market Interface Committee (MIC) to determine the amount of SPP 2 10/18/00

3 SPP Report on September 7, 2000 TLR Event relief required by native load and network service. This process identifies generators serving native load and network service that significantly contribute to the loading of the constraint and allocates a proportionate amount of the necessary firm relief to the control areas where those generators are located. The NERC Distribution Factor Task Force was charged by the SCS to produce a calculator for use this past summer by the Security Coordinators that would indicate the proportion of relief allocated to native load and network service. The calculator is currently available on the Security Coordinator Information System (SCIS) as the Native Load Report. Below is the calculation that SPP performed on September 7 for the TLR Level 5 event. Native Load Service (per generator basis) with Contribution Factors > 5% GLDF Generator Energy on Generator-to-CA Load (%) Loading Flow gate 1NM G CA=AECI NM G CA=AECI STFRG CA=AECI ESSEX CA=AECI AECI Total ANO U CA=EES ANO U CA=EES EES Total DEGR U CA=EES DEGR U CA=EES BLAK U CA=EES BLAK U CA=EES KENNETT CA=SPA SPP 3 10/18/00

4 SPP Report on September 7, 2000 TLR Event The calculator indicated that generators serving native load or providing network service in the AECI, CSWS, Entergy and SPA control areas contributed to the post-contingency loading on the Monitored Element. The calculator results were updated to reflect current generator status at the time of the TLR. Contributions from generators that were off-line were removed. The calculator indicated that CSWS native load service contributed approximately 241 MW to the flow gate loading. Entergy s contribution was 149 MW, AECI s contribution was 68 MW and SPA s was 7 MW. The IDC indicated that the contributions from the existing firm point-to-point transactions totaled approximately 328 MW. The total firm contributions were then 793 MW. Therefore, the CSWS share of any relief requested was 241/793 or 30.4%. Entergy s share was 149/793 or 18.8%, AECI s share was 68/793 or 8.6% and SPA s share was 7/793 or 0.9%. Since it was so small compared to the contributions, SPA s contribution was neglected and SPA was not asked to redispatch. The point-to-point share was 328/793 or 41.3%. Seeking 100 MW of relief on the flow gate, SPP requested that CSWS reduce loading on the flow gate by 30 MW, Entergy 19 MW, AECI 9 MW and 41 MW of relief from point-to-point transactions via the IDC. This data is presented in table form below. Flow Gate Contribution Control Area (MW) (%) Requested Flow Reduction (MW) AECI CSWS EES SPA Point-to-Point Totals Utilizing the generation shift factors (GSFs), SPP worked with the impacted control areas to develop generator-pair options for redispatch. Although slow to materialize, reductions in flow did occur as a result of redispatch. AECI totally curtailed a firm transaction to GRDA that was flowing at 43 MW following the initial Level 5 curtailments. GRDA responded by replacing this lost capacity with generation at its Salina Plant. AECI estimates that this provided approximately 8 MW of relief on the flow gate. CSWS estimates that it achieved 366 MW of redispatch between the time the TLR Level 5 was issued and 1800 CDT. This involved generation in Texas reversing flows on the HVDC ties to ERCOT, Northeastern Station #1, Southwestern Station # s 1 and 2, Arsenal Hill #5, Know Lee #5, Lieberman # s 3 and 4, and Wilkes # s 2 and 3. It is estimated that the relief provided by this re-dispatch was approximately 31 MW. Similarly, Entergy estimates that it effectively redispatched some 631 MW by 1800 CDT at its White Bluff and Lewis Creek plants. The Tenaska IPP units at Frontier also contributed to this redispatch effort. Entergy estimates that this redispatch provided approximately 20 MW of relief on the flow gate. The total relief requested of firm point-to-point was 41 MW. SPP 4 10/18/00

5 NERC TRANSMISSION LOADING RELIEF (TLR) PROCEDURE LOG FILE SAVED AS: Q:\SECURITY DOCUMENTS\NERC TLR Log\SPP_ XL INCIDENT : SPP_ DATE: 09/07/00 IMPACTED SECURITY COORDINATOR : SPP ID NO: 5017 I N I T I A L C O N D I T I O N S Western Resources Wolf Creel Unit 1 out of service until 1403 CST Limiting Flowgate (LIMIT) Rating Contingent Flowgate (CONT.) ODF Fort Smith 500/161 kv transformer 480 Fort Smith 500/345 kv transformer 76% TLR Levels Priorities 0: TLR Incident Canceled NS Service over secondary receipt and delivery points 1. Notify Security Coordinators of potential problems. NH Hourly Service 2a, 2b, 2c: Halt additional "contributing" transactions. ND Daily Service 3: Curtail Non-firm transactions (state priorities being curtailed). NW Weekly Service 4. Reconfigure and redispatch to continue firm transactions if needed. NM Monthly Service 5: Curtail Firm Transmission Service. NN Non-firm imports for native load and network customers from 6: Implement emergency procedures. non-designated network resources F Firm Service T L R A C T I O N S TLR 3,5 TLR 3,5 LIMIT CONT. LEVEL TIME Priority NO. TX MW Present Post-Cont. Present C O M M E N T S A B O U T A C T I O N S Curtail Curtail Flow Flow Flow 2c Issued TLR Level 2c ,2,3,5, Re-issued TLR as Level 3, 32 MW of relief provided 2c Re-issued TLR as Level 2c 2c Re-issued TLR as Level 2c , NL/NS* Re-issued TLR as Level 5, 41 MW of relief from firm PTP transactions, 58 MW of relief from Native Load/Network Service* Re-issued TLR Level Re-issued TLR Level Re-issued TLR Level Re-issued TLR Level 5 2c Re-issued TLR as Level 2c, released firm transactions and Native Load/Network Service Released TLR

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