ML17072A376
| ML17072A376 | |
| Person / Time | |
|---|---|
| Site: | Saint Lucie  |
| Issue date: | 03/21/2017 |
| From: | Nextera Energy |
| To: | NRC/RGN-II |
| References | |
| Download: ML17072A376 (37) | |
Text
St. Lucie Unit 1 Regulatory Conference Plant Centered Loss Of Offsite Power March 21, 2017
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Attendees
- Tom Summers, Regional Vice President
- Mark Jones, Site Engineering Director
- Steve Merrill, Operations Shift Manager
- Anil Julka, Fleet Risk and Reliability Manager
- Mike Snyder, Site Licensing Manager
- Larry Nicholson, Fleet Licensing Director 4
Agenda
- Opening Remarks - Tom Summers
- Event & Operational Response - Steve Merrill
- Cause & Corrective Action - Mark Jones
- Risk Significance - Anil Julka
- Closing Remarks - Tom Summers 5
Opening Remarks Tom Summers Regional Vice President
Event Investigation Mark Jones Site Engineering Director
Unit 1 experienced an automatic trip from 38% power Event Summary
- During power ascension following an outage, Unit 1 tripped at 38% power.
- Safety related electrical busses did not transfer to the Startup Transformers as expected.
- Safety related electrical busses were automatically powered from the Emergency Diesel Generators without complication.
- Operators manually restored power to the first safety related electrical bus from the Startup Transformers at 55 minutes following trip.
No equipment damage occurred. Power from switchyard remained available during event. All remaining systems responded as designed.
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Unit 1 trip was caused by actuation of the Inadvertent Energization (INAD) generator protection circuit Immediate Cause Determination
- INAD actuation was not blocked as designed due to missing wire on Main Generator synchronization selector switch.
- Missing wire resulted from 2013 human error during modification to Unit 1 automatic synchronizer circuit and prevented block of INAD circuit.
- INAD actuation prevented automatic bus transfer to Startup Transformer.
Manual bus transfer to Startup Transformer remained.
- Condition could cause INAD actuation only after manual synch. and only when power exceeded 38%.
- Manual synchronization is atypical in startup. August 2016 was first manual synchronization since modification implementation.
- Operation following previous automatic synchronizations uneventful.
Missing wire would only cause event at 38% power during power ascension after manual synchronization of the Main Generator.
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Event Summary and Operational
Response
Steve Merrill Operations Shift Manager
Event Summary - Initial Conditions
- Unit 1 at 38% power following an outage.
- Standard practice is to have additional staffing in the control room for oversight and control board peer checks during the plant startup.
Minimum is one Unit Supervisor and two Reactor Operators.
The following additional operators were in the Control Room:
- Shift Manager
- Extra Reactor Operator
- Assistant Operations Manager (SRO licensed)
- Both trains of Emergency Diesels (EDG) and Auxiliary Feedwater (AFW) were operable.
Technical Specifications require all AFW pumps and both EDG trains available prior to Mode 1 change.
Risk mitigation factors included additional licensed operators and key safety system availability.
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Event Summary - Immediate Response
- Actuation of the Main Generator Lockout relay caused an automatic turbine and reactor trip.
- The lockout sequence inhibited automatic transfer from auxiliary to the startup transformers powering safety related buses; resulting in a plant centered loss of power connection to the switchyard.
- Both Unit 1 Emergency Diesel generators started and automatically and powered their respective safety related bus loads.
- Operators recognized offsite power remained available to the station switchyard with normal voltage and Unit 2 remained unaffected.
Operators diagnosed the event with multiple and diverse indications.
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Event Summary - Restoration Steps
- The unit was stable in hot standby using natural circulation cooling for decay heat removal with AFW and Atmospheric Steam Dump Valves.
- Auxiliary Feed Water was manually initiated per procedure and ahead of automatic actuation.
The low power history and shutdown of the reactor coolant pumps resulted in a smaller RCS heat load to control.
- Lower RCS heat input extends the inventory demands for the Condensate Storage Tanks.
- Operators used plant specific Combustion Engineering Emergency Operating Procedures to diagnose and control the plant.
- An Unusual Event was declared for plant power separation from the switchyard.
- In-plant verifications were performed to ensure no equipment damage prior to electrical bus restoration.
Offsite power was restored to both of Unit 1s safety related busses within 70 minutes.
All breakers were closed from the control room.
Operators and systems performed as expected during the recovery.
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Switchyard Distribution 3 tie lines to TREASURE MIDWAY 2 MIDWAY 1 the grid - Transmission tie line Transmission tie line Transmission tie line Treasure and Midway WEST BUS BAY 4 BAY 3 BAY 2 BAY 1 BAY 1A B S/U A S/U TRANSFORMERS TRANSFORMERS 230 kV EAST BUS 230 kV UNIT 2 UNIT 1 2B Start up 1B Start up 2A Start up 1A Startup Transformer Transformer Transformer Transformer 230 kV 230 kV Down to Down to 4.16 & 6.9 kV 4.16 & 6.9 kV Power to the switchyard was never lost and no equipment was damaged.
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Unit 1 - Main Power Distribution System From BAY 2 To BAY 1 in switchyard From BAY 4 in switchyard in switchyard 2A S/U 1A S/U 1B S/U 2B S/U 1A Main 1B Main TRANSFORMER TRANSFORMER TRANSFORMER TRANSFORMER Transformer Transformer 1A AUX 1B AUX Transformer Transformer A4 4.16 KV B4 4.16 KV Non-safety Non-safety cross tie cross tie A1 6.9 KV B1 6.9 KV Main Generator Safety Related Bus Safety Related Bus Safety Related Bus A3 4.16 KV AB 4.16 KV B3 4.16 KV A2 4.16 KV B2 4.16 KV
- Open Breaker.
Unit 2 SBO - Bus
- Breakers remained closed.
1A EDG Safety 1B EDG - Breakers closed
- EDG Breakers closed automatically. Cross tie from the control room to restore power from the switchyard An automatic fast dead bus transfer swaps the circled breakers from Auxiliary to Start-up transformers after a unit trip within 10 cycles.
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Unit 1 - Main Power Distribution System FROM BAY 2 TO BAY 1 FROM BAY 4 2A S/U 1A S/U TRANSFORMER 1B S/U 2B S/U TRANSFORMER AMAIN BMAIN TRANSFORMER TRANSFORMER A AUX B AUX A4 4.16 KV B4 4.16 KV Non-safety Non-safety Cross tie Cross tie 1A1 6.9 KV 1B1 6.9 KV Main Generator Safety Related Bus Safety Related Bus Safety Related Bus 1A2 4.16 KV 1A3 4.16 KV 1AB 4.16 KV 1B3 4.16 KV 1B2 4.16 KV Unit 2 SBO Energized Bus 1A EDG Safety 1B EDG Cross tie
- Closed Breaker, energized.
- Open Breaker.
Normal Power Alignment 16
Unit 1 - Main Power Distribution System FROM BAY 2 TO BAY 1 FROM BAY 4 2A S/U 1A S/U AMAIN BMAIN 1B S/U 2B S/U TRANSFORMER TRANSFORMER TRANSFORMER TRANSFORMER A AUX B AUX A4 4.16 KV B4 4.16 KV Non-safety Non-safety Cross tie Cross tie 1A1 6.9 KV 1B1 6.9 KV Main Generator Safety Related Bus Safety Related Bus Safety Related Bus 1A2 4.16 KV 1A3 4.16 KV 1AB 4.16 KV 1B3 4.16 KV 1B2 4.16 KV Unit 2 SBO 1A EDG Safety 1B EDG De-energized Bus Cross tie
- Closed Breaker, energized.
- Open Breaker.
Loss Of Power Alignment 17
Unit 1 - Main Power Distribution System FROM BAY 2 TO BAY 1 FROM BAY 4 2A S/U 1A S/U TRANSFORMER TRANSFORMER AMAIN 1B S/U 2B S/U BMAIN TRANSFORMER TRANSFORMER A AUX B AUX A4 4.16 KV B4 4.16 KV Non-safety Non-safety Cross tie Cross tie 1A1 6.9 KV 1B1 6.9 KV Main Generator Safety Related Bus Safety Related Bus Safety Related Bus 1A2 4.16 KV 1A3 4.16 KV 1AB 4.16 KV 1B3 4.16 KV 1B2 4.16 KV Unit 2 SBO 1A EDG Safety 1B EDG Cross tie Energized Bus
- Closed Breaker, energized.
- Open Breaker. Normal Mode 3 Alignment 18
Control Room Electrical Panel Distribution Panel B Side Auxiliary Transformer Safety Related 4.16 kv bus Non-safety 4.16 kv bus Bus Tie Breakers Startup Transformer Emergency Diesel Generator 19
Broader perspective for LOOP and SBO events Power Restoration Scenarios
- Loss Of Offsite Power and Station Black Out scenarios for electrical power recovery paths include procedure steps for the following:
- Automatic or local start of an emergency diesel generator.
- Restoring either electrical train through the Startup Transformers.
- Using Safety Related Station Blackout cross tie connections.
- Using non-safety cross tie connections between Startup Transformers.
Implementation of any recovery path mitigates the event.
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New information on training program Operations Training
- Loss Of Offsite Power (LOOP) and Station Black Out (SBO) scenarios are components of Initial and Continuing Operator training programs.
- A two year frequency for continuing licensed operator training is required for LOOP and SBO, with a week of classroom and simulator training focused on electrical system recovery.
- Nine separate Job Performance Measures in licensed operator training cover the different proceduralized methods to power a safety related bus.
- JPMs provide systematic training evaluations for Operator performance during field walk through and simulator sessions.
Training and procedures ensure repeatable operator performance.
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New information on simulator evaluations Operations Training
- Simulator crew evaluation results:
- All crews (43 of 43) in the biennial simulator training from 2010 to 2016 successfully restored power to a safety related bus in Station Blackout scenarios in under 24 minutes.
No crew failures noted in training.
- Four loss of power connection to switchyard simulator scenarios were performed in 2017.
Half of the site licensed operators participated, with each scenario varied for power level, AFW availability, and EDG availability.
All crews restored power from the switchyard to the first safety related bus in less than 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.
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PRA and Risk Significance Anil Julka Fleet Nuclear Risk and Reliability Manager
Risk Significance in Choice Letter
- SPAR results
- Initial SPAR analysis was significantly conservative.
- Based on NEE-supplied information, NRC added credit for:
Electrical room cooling.
Feedwater recovery following offsite power availability.
Realistic CST unavailability.
Realistic failure probability for feed and bleed.
- The risk dropped to slightly greater than 1E-06.
- NEE and NRC agree that these credits were appropriate.
- NEE reviewed the results of the SPAR analysis after these changes were made - observations:
- 7 of the top sequences are station blackout (SBO) sequences with failure of offsite power recovery in 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.
- SPAR model offsite power recovery timeframe is based on industry-average data.
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New information on SPAR Human Reliability Analysis Offsite Power Recovery - Case 1
- Plant centered loss of power to the switchyard
- As indicated by Operations, this was a simple LOOP recovery.
- Time to restore power was well below the industry average.
- The actual recovery time during the event was 70 minutes (both trains) with both EDGs running; validated by observed simulator runs.
- Past training records of simulator runs validated the short recovery time.
- NEE changes to SPAR analysis
- The 6-hour industry average of offsite power recovery failure was replaced with a human reliability analysis.
- SPAR-H analysis of this operator action gives a failure probability of 4.4E-03.
Offsite power recovery credit specific to the Performance Deficiency should be used in lieu of industry-average historical data.
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New information on industry comparisons Plant centered power loss industry comparisons
- Although the NEE PRA model includes a range of equipment failure possibilities, the Unit 1 event initiator did not have any irreversible conditions as noted in industry plant centered many LOOP event initiators.
Industry Plant Centered LOOP Unit 1 Event Industry LOOPs complications Failure in isophase bus duct No YES Non-segregated bus explosion No YES Switchgear fire in non-safety bus No YES Startup Transformer damage No YES Failure of both 230kV breakers No YES Design vulnerabilities No YES Emergency Diesel Generator OOS No YES Switchyard component failures No YES None of these equipment failure initiators were part of the Unit 1 Performance Deficiency.
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New information on PRA sensitivity to EDG availability Test and Maintenance - Case 2
- Maintenance unavailability
- A typical SDP assumes average T&M unavailability unless the T&M activity is associated with the Performance Deficiency.
- A realistic estimate of the risk of this Performance Deficiency assumes zero T&M unavailability. Basis for this conclusion:
This plant-specific Performance Deficiency could have only occur at 38% power ascension following manual synchronization of the main generator.
Important pieces of equipment are not removed from service for maintenance during this short time (approximately 16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br />) between Mode 1 and power ascension.
Records for last 3 years show EDG, AFW, and CCW were available below 40% during power ascension.
- Risk falls below 1E-06 if only the EDGs test and maintenance unavailability is set to zero; and other T&Ms left at average values.
- Risk falls below 1E-06 if the EDGs test and maintenance is simply halved.
It is our normal practice to not remove key equipment from service during power ascension.
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New information on station blackout risk mitigation Local Operation of Turbine-Driven AFW Pump Case 3
- There is clear procedural guidance for this action specified by procedures and tested in training.
- Local Operation of the steam driven 1C Auxiliary Feedwater Pump is specified in plant procedures .
- Job Performance Measure used to ensure Operator proficiency.
- JPM - Locally Operate 1C Auxiliary Feedwater Pump.
Local operation of the steam driven AFW pump is credited in NEE PRA.
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New information on station blackout risk mitigation Local Operation of Turbine-Driven AFW Pump Case 3
- NEE PRA model does credit manual feeding of the Steam Generators via local operation of the steam driven Auxiliary Feedwater pump.
- In combination with the adjustments for offsite power recovery and maintenance unavailability, credit for this action in the SPAR model lowers the CCDP to 2.4E-07.
Local operation of the steam driven AFW pump should be credited in the SPAR model.
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New information Combination of Changes - Case 4
- SPAR model
- In combination with the adjustments for offsite power recovery, maintenance unavailability and AFW local operator action, credit for this action in the SPAR model lowers the CCDP to 2.4E-07.
- NEE PSL1 PRA model
- PSL1 Regulatory Guide 1.200 compliant PRA model for CCDP is 3.2E-07.
Incorporation of these changes results in SPAR model and NEE PSL1 PRA model correlation.
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Summary of each Case and FPL PRA model Results and Comparisons LOOP Model Comments CCDP SPAR 1.2E-06 FPL/NRC agreed-upon adjustments NRC Input SPAR Offsite power recovery failure replaced with 4.7E-07 FPL Changes - Case 1 operator action to recover offsite power SPAR 6.4E-07 EDG T&M set to 0 FPL Changes - Case 2 SPAR 4.7E-07 Credit for local operation of TDAFWP C FPL Changes - Case 3 SPAR Offsite power recovery failure replaced with FPL Changes - Case 4 2.4E-07 operator action, EDG T&M set to 0, and credit (combination of Cases 1, 2 and 3) for TDAFWP local operation FPL 3.2E-07 FPLs PSL1 RG-1.200-compliant PRA model PRA Model NRC results are from choice letter dated February 2, 2017 FPL results are from SPAR and in-house model - includes FPL inputs and assumptions noted in previous slide 31
New information for three inputs to SDP Conclusions
- 1) Application of appropriate credit for offsite power recovery by operators within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />, considering the new SPAR-H analysis.
- 2) Adjustment to only EDG maintenance unavailabilities to properly reflect the actual and historical availability conditions associated with this Performance Deficiency.
- 3) Application of credit for local operation of the turbine-driven AFW pump that was not previously considered.
- Combining all of them reduces the CCDP to the low E-7 range, consistent with the results using the NEE PSL1 PRA model.
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Closing Remarks Tom Summers Regional Vice President
Improvements to Offsite Power Reliability
- Importance of Offsite Power
- Any failure is unacceptable and must be mitigated.
- We are committed to improving reliability of offsite power through plant to grid modifications.
- Addition of another Bay in the switchyard for reliability in 2014.
- Treasure substation modification for independent sources to the switchyard in 2015.
- Turnpike underground transmission line from the switchyard added for power line protection in 2016.
- Midway station barriers added for transformer protection in 2017.
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Closing Remarks 35
Questions and Clarifications