ML13345A157
| ML13345A157 | |
| Person / Time | |
|---|---|
| Site: | Comanche Peak  |
| Issue date: | 12/11/2013 |
| From: | Kennedy K NRC/RGN-IV/DRP |
| To: | Flores R Luminant Generation Co |
| References | |
| NOED 13-4-004, TAC MF3187 | |
| Download: ML13345A157 (5) | |
Text
December 11, 2013 Rafael Flores, Senior Vice President and Chief Nuclear Officer Attention: Regulatory Affairs Luminant Generation Company LLC Comanche Peak Nuclear Power Plant P.O. Box 1002 Glen Rose, TX 76043
SUBJECT:
NOTICE OF ENFORCEMENT DISCRETION FOR LUMINANT GENERATION COMPANY LLC (TAC NO. MF3187, NOED NO. 13-4-004)
Dear Mr. Flores:
By letter, dated December 9, 2013 (ML13345A261), Luminant Generation Company LLC requested that the U.S. Nuclear Regulatory Commission (NRC) exercise discretion to not enforce compliance with the actions required in Comanche Peak Nuclear Power Plant (CPNPP), Units 1 & 2, Technical Specification (TS) 3.8.1, AC Sources - Operating, Required Action C.2. This letter documented information previously discussed between Mr. Tim Hope, Manager, Regulatory Affairs, and other members of your staff, and the NRC in a telephone conference on December 5, 2013, at approximately 10:00 a.m. (CST) (all time references below will be in Central standard time).
The principal NRC staff members who participated in the telephone conferences included the following: Kriss Kennedy, Director, Division of Reactor Projects, Region IV (RIV); Tom Blount, Director, Division of Reactor Safety, RIV; Jeff Clark, Deputy Director, Division of Reactor Safety, RIV; Louise Lund, Deputy Director, Division of Operating Reactor Licensing, Office of Nuclear Reactor Regulation (NRR); Wayne Walker, Chief, Project Branch A, RIV; Michael Markley, Chief, Plant Licensing Branch IV-1, NRR; Lynnea Wilkins and Matthew Bartlett, Project Managers, Plant Licensing Branch IV-1, NRR; Sheldon Stuchell, Notice of Enforcement Discretion (NOED) Process Coordinator, NRR; Jacob Zimmerman, Chief, Electrical Engineering Branch, NRR; Gurcharan Matharu, Senior Electrical Engineer, NRR; Roy Mathew, Senior Electrical Engineer, NRR; Gerald Waig, Technical Specification Branch, NRR; David Loveless, Senior Reactor Analyst, RIV; John Kramer, Senior Resident Inspector, RIV; Rayomand Kumana, Resident Inspector, RIV; Jeff Circle, Senior Reliability and Risk Analyst, PRA Operational Support Branch, NRR; and Antonios Zoulis, Reliability and Risk Analyst, PRA Operational Support Branch, NRR.
On December 4, 2013, at 1:41 p.m., a loss of safeguards electrical power occurred during planned modification work to install an additional 138 kV transformer (XST1A). Power was lost to the 345 kV transformer (XST2) which at the time was providing power to the 6.9 kV UNITED STATES NUCLEAR REGULATORY COMMISSION RE G IO N I V 1600 EAST LAMAR BLVD ARLINGTON, TEXAS 76011-4511
safeguards buses for both CPNPP Units 1 and 2. It was determined that the loss of offsite power to the safeguards buses was caused during the modification work when your staff inadvertently began to cut into an energized 6.9 kV cable for transformer XST2, rather than an intended de-energized cable for transformer XST1.
You stated that at 1:41 p.m. on December 4, 2013, both CPNPP units entered Technical Specification 3.8.1, Condition C, Required Action C.2, to restore one required offsite circuit to operable status within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Further, TS 3.8.1 required that if TS 3.8.1, Condition C, could not be met within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, both CPNPP units would be required to enter Condition G of TS 3.8.1, and be in Mode 3 in 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and Mode 5 in 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. Enforcement discretion was sought to permit additional time to make repairs and restore transformers XST1 or XST2 to operable status. An additional 14 hours1.62037e-4 days <br />0.00389 hours <br />2.314815e-5 weeks <br />5.327e-6 months <br /> was requested to restore transformers XST1 or XST2, such that the completion time of Required Action C.2 would expire at 3:41 a.m. on December 6, 2013. This letter documents the telephone conversation on December 5, 2013, which concluded at approximately 1:00 p.m. between CPNPP and the NRC staff, when the NRC staff verbally granted this NOED. We understand that CPNPP pursued parallel paths to restore transformers XST1 and XST2, and the condition causing the need for this NOED was corrected by CPNPP with the restoration of transformer XST2 to operable status, allowing both CPNPP units to exit TS 3.8.1, Required Action C.2, and this NOED at 5:17 p.m. on December 5, 2013.
Further, we understand that transformer XST1 was restored to operable status at 12:19 a.m. on December 6, 2013.
During the teleconference on December 5, and further elaborated in your December 9, 2013, letter, your staff indicated that from a risk perspective, it was undesirable to place both CPNPP units into a Mode 3 configuration in that both CPNPP units were operating in a stable configuration with offsite power available to support the non-safety buses for the balance of plant while safety-related power was being provided by the emergency diesel generators (EDGs) to their respective 6.9 kV buses. Based on actual plant conditions on December 5, 2013, quantitatively your staff estimated the Incremental Conditional Core Damage Probability (ICCDP) to be approximately 3.49E-07 (for both units), and the Incremental Conditional Large Early Release Probability (ICLERP) to be approximately 1.97E-08 (for both units). Additionally, it was noted that the estimated ICCDP and ICLERP values did not take into account various additional conservatisms associated with compensatory actions which had been put in place consistent with the license amendment which supported the modification process that was underway to install transformer XST1A when the event occurred. The results of you staffs quantification were independently corroborated by NRC analysts and were determined to be less than the guidance thresholds in Inspection Manual Chapter 0410, Notices of Enforcement Discretion, (ML13071A487).
From a qualitative perspective, your staff noted that maintaining the units in the Mode 1 operating condition provided additional redundancy and diversity for core cooling through the balance of plant systems. However, if the units would have been required to transition to Mode 3, and then Mode 5, the balance of plant systems would become unavailable for core cooling, instead relying on the auxiliary feedwater (AFW) system and then the residual heat removal (RHR) system to provide this function. The AFW and RHR systems would have been powered from the 6.9 kV safeguard buses, adding additional burden to the safeguards buses which were being supplied from the EDGs at the time. Your staff also stated that there was no net increase in radiological risk to the public.
Your staff implemented compensatory risk management measures as conditions of the license amendment that were in place to support the transformer XST1A installation, maintained those compensatory measures prior to making the request for enforcement discretion, and ensured these compensatory measures remained in effect throughout the proposed period of discretion.
These additional compensatory risk management measures included (1) ensuring the availability of the stations alternate power diesel generators; (2) completing all testing and maintenance activities associated with the EDGs, AFW system, cooling water systems, and transformer XST2 prior to, and then suspending further maintenance activities on these systems during the special 14-day completion time for the license amendment to install transformer XST1A; (3) maintaining a roving fire watch for transformer XST2 during the 14-day completion time; (4) actively monitoring local weather conditions and forecasts to assess potential impacts on plant conditions; and (5) conducting daily communications with the transmission grid operator to ensure that no issues with offsite transmission lines feeding CPNPP would cause post trip switchyard voltages to exceed procedural requirements.
Your staff also stated that no severe weather was forecast (i.e., severe thunderstorms or tornadoes) which could challenge offsite power availability during the proposed period of enforcement discretion, and grid conditions were normal, and no maintenance would be performed on safety-related equipment. However, it was acknowledged that a winter storm warning was in effect prior to and during the discretion period, but based on historical data, CPNPP had not experienced challenges due to snow, sleet, or freezing rain typically associated with winter storms in Texas. Challenges to grid conditions were not expected during the winter storm, nor were any actually experienced during the discretion period.
Your staff stated that the proposed change did not involve a significant hazard based on the three standards set forth in 10 CFR 50.92(c), and did not involve adverse consequences to the environment such that the proposed change meets the categorical exclusion set forth in 10 CFR 51.22(c)(9). The CPNPP Station Operations Review Committee and Plant Manager approved the NOED request on December 5, 2013, prior to the verbal request for an NOED.
Because the request was a one-time extension of the required completion times for repairs, your staff stated that a follow-up license amendment request was not required.
Based on the NRC staffs evaluation of your request, the NRC has concluded that granting this NOED is consistent with the NRCs Enforcement Policy and staff guidance, and would have no adverse impact on public health and safety. Therefore, as communicated to your staff at 1:00 p.m. on December 5, 2013, the NRC exercised discretion to not enforce compliance with Technical Specification 3.8.1, Condition C, Required Action C.2, for an additional period of 14 hours1.62037e-4 days <br />0.00389 hours <br />2.314815e-5 weeks <br />5.327e-6 months <br />, which expired at 3:41 a.m. on December 6, 2013.
In addition, as discussed on December 5, 2013, the NRC staff agreed with your determination that a follow-up Technical Specification amendment is not needed. The staff concluded that an amendment (either a temporary or permanent amendment) is not necessary because this NOED involves a nonrecurring noncompliance and only involves a single request for extending the period of time for Technical Specification 3.8.1, Condition C, Required Action C.2, to restore one required offsite circuit to operable status within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
As stated in the Enforcement Policy, action will be taken, to the extent that violations were involved, for the root cause that led to the noncompliance for which this NOED was necessary.
Sincerely,
/RA/
Kriss M. Kennedy, Director Division of Reactor Projects Docket: 50-445; 50-446 License: NPF-87; NPF-89 50-313 Electronic Distribution for Comanche Peak Nuclear Power Plant
ML13345A157 ADAMS: No Yes SUNSI Review Complete Reviewer Initials: RDA Publicly Available Non-Sensitive Non-publicly Available Sensitive SPE:RIV/DRP/A C:RIV/DRP/A SRA:RIV/DRS C:RIV/ACES RAlexander WWalker DLoveless HGepford
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/RA by RDeese via E/ /RA via E/
12/11/13 12/11/13 12/11/13 12/11/13 PM:NRR/DORL/LPL4 D:RIV/DRS DD:NRR/DORL D:RIV/DRP JSebrosky TBlount LLund KKennedy
/RA via E/
/RA via E/
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