IR 05000220/2013010
| ML13344A989 | |
| Person / Time | |
|---|---|
| Site: | Nine Mile Point  |
| Issue date: | 12/10/2013 |
| From: | Bill Dean Region 1 Administrator |
| To: | Costanzo C Constellation Energy Nuclear Group |
| Schroeder D | |
| References | |
| EA-13-186 IR 13-010 | |
| Download: ML13344A989 (14) | |
Text
UNITED STATES cember 10, 2013
SUBJECT:
FINAL SIGNIFICANCE DETERMINATION OF GREEN FINDING - NINE MILE POINT NUCLEAR STATION UNIT 1 (NRC INSPECTION REPORT NO.
Dear Mr. Costanzo:
This letter provides you the final significance determination for the preliminary greater than Green finding discussed in the U.S. Nuclear Regulatory Commission (NRC) letter dated September 23, 2013 (ML13266A237)1. As described in the September 23, 2013, letter, the finding was associated with the Constellation Energy Nuclear Group, LLC (CENG) Nine Mile Point (NMP) Unit 1 loss of shutdown cooling (SDC) event that occurred on April 16, 2013, during a scheduled refueling outage. Specifically, inadequate CENG procedures for restoration following an unexpected loss of direct current (DC) control power resulted in an unplanned loss of all SDC. We note that there was no actual safety consequence to the event, because the operators restored SDC in a timely manner. The finding was presented at an exit meeting on July 25, 2013, and is described in detail in an NRC inspection report issued on August 13, 2013 (NRC Inspection Report 05000220/2013003 and 05000410/2013003; ML13225A471).
To ensure that the NRC used the best available information in its final significance determination, the September 23, 2013, letter provided CENG the option to attend a regulatory conference (RC) or reply in writing to provide its position on the facts and assumptions the NRC used to arrive at the findings preliminary safety significance. CENG requested and attended a RC that was open for public observation on November 1, 2013, at the NRCs Region I office in King of Prussia, Pennsylvania. A copy of the CENG presentation and a list of RC attendees are included in Enclosures 3 and 4 to this letter.
The NRC determined, after careful consideration of the information developed during the inspection, the preliminary risk assessment, and the additional information CENG provided during the RC, that the inspection finding is of very low safety significance, and is therefore appropriately characterized as Green. A detailed description of the NRCs basis for concluding the finding is of Green significance is provided in Enclosure 1. The NRC staff determined that given the specific circumstances involved there was a very high likelihood of success of manual
Designation in parentheses refers to an Agency-wide Documents Access and Management System (ADAMS) accession number. Documents referenced in this letter are publicly-available using the accession number in ADAMS. operator actions to restore SDC or maintain adequate reactor vessel inventory to prevent core damage. Although the finding was determined to be of very low safety significance, this finding revealed a significant weakness in CENGs outage risk management. The NRC staff intends to inspect your fleet corrective actions to improve outage risk management during complex test and maintenance evolutions in accordance with our baseline inspection program.
The NRC determined that the original finding concerning the adequacy of procedures for properly restoring a battery bus following a loss of DC power was a violation of NMP Unit 1 Technical Specification 6.4.1, Procedures. Because the issue is of very low safety significance (Green), is not willful, and because CENG restored compliance within a reasonable period of time and entered this issue into its Corrective Action Program (CR-2013-002926 and CR-2013-002916), this finding is being treated as a non-cited violation (NCV) consistent with Section 2.3.2 of the NRC Enforcement Policy. An additional Green finding was identified, related to the unexpected loss of DC control power which occurred because a contractor errantly opened the breaker cabinet door for the vital DC bus 12 while preparing for an unrelated modification. These findings are described in Enclosure 2.
The NRC has concluded that information regarding the reasons for the violations, the corrective actions taken and planned to correct the violations and prevent recurrence, and the date when full compliance was achieved has been already adequately addressed on the docket in NRC Inspection Report 05000220/2013003 and 05000410/2013003, dated August 13, 2013, in the September 23, 2013, NRC letter and its enclosure, and in this letter and its enclosures.
Therefore, you are not required to respond to this letter unless the description herein does not accurately reflect your corrective actions or your position. If you contest these NCVs or their significance, you should provide a response within 30 days of the date of this letter, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN.: Document Control Desk, Washington, D.C. 20555-0001, with copies to the Regional Administrator, Region I, 2100 Renaissance Boulevard, Suite 100, King of Prussia, PA 19406; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, D.C. 20555-0001; and the NRC Resident Inspector at NMP.
In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, its enclosure, and your response, if you choose to provide one, will be made available electronically for public inspection in the NRC Public Document Room located at NRC Headquarters in Rockville, MD, and from the NRCs Agencywide Documents Access and Management System (ADAMS), accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html. To the extent possible, your response, if you choose to provide one, should not include any personal privacy, proprietary, or safeguards information so that it can be made available to the Public without redaction. Should you have any questions regarding this matter, please contact Mr. Daniel Schroeder, Chief, Projects Branch 1, Division of Reactor Projects in Region I, at (610) 337-5262.
Sincerely,
/RA/
William M. Dean Regional Administrator Docket No. 50-220 License No. DPR-63 Enclosures:
1. Summary of November 1, 2013 Regulatory Conference; Basis for NRC Final Significance Determination Conclusion 2. Description of NRC Findings 3. Regulatory Conference Agenda/List of Attendees (ML13340A088)
4. CENG Nine Mile Point Unit 1 Regulatory Conference Loss of Shutdown Cooling Presentation (ML13340A091)
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ML13344A989 Non-Sensitive Publicly Available SUNSI Review Sensitive Non-Publicly Available OFFICE RI/ORA RI/DRP RI/DRS RI/DRP RI/DRS NAME MMcLaughlin/MMM* DSchroeder/DLS* WSchmidt/AAR for* DRoberts/DJR* RLorson/ RKL*
DATE 11/22/13 12/2/13 12/2/13 12/09/13 12/09/13 OFFICE RI/ORA RI/ORA HQ/OE HQ/NRR RI/ORA RZimmerman/RZ by SWeerkakkody/SW by NAME EMonteith/ ELM NLO* B Bickett/ BAB* WDean/WMD email* email*
DATE 12/09/13 12/09*13 12/2/13 12/2/13 12/10/13
- Concurrence on previous page Letter to Christopher Costanzo from William M. Dean dated December 10, 2013 SUBJECT: FINAL SIGNIFICANCE DETERMINATION OF GREEN FINDING - NINE MILE POINT NUCLEAR STATION UNIT 1 (NRC INSPECTION REPORT NO.
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Summary of November 1, 2013, Regulatory Conference; Basis for NRC Final Significance Determination Conclusion Summary of November 1, 2013, Regulatory Conference During the regulatory conference (RC), Constellation Energy Nuclear Group (CENG) provided several factors that, they believed, mitigated the significance of the issue. CENG noted that:
Nine Mile Point (NMP) Unit1 reactor operators (ROs) who were designated to observe critical plant parameters (such as reactor coolant temperature and level) recognized that shutdown cooling (SDC) had been lost within 4 minutes of the occurrence. Then, ROs who were dedicated to restore SDC pump breakers and were staged (with the applicable procedures) in the Control Room and in the plant, restored the pump breakers in under 15 minutes and SDC flow resumed within 27 minutes. CENG indicated that the prompt identification of and recovery from this event should be factored into the risk analysis because there was essentially no scenario in which the loss of SDC would not be identified and addressed prior to core damage occurring. Specifically, CENG pointed to the following:
1. If the ROs had not identified that SDC had been lost, it would have been easily identified by any of a number of other recognizable cues:
a. There were multiple redundant indications monitoring reactor coolant temperature and level, and those indications were not impacted by the loss of the direct current (DC) bus, and would have alerted ROs to the issue.
b. There were 24 alarms associated with lowering reactor level which would have sounded in the Control Room prior to reaching the top of active fuel, and those alarms were not affected by the loss of the DC bus.
c. The event would have been identified by: (i) the numerous workers on the refuel floor (and others observing it from cameras) who would have seen steam from the boiling and/or reported the increased temperature and humidity conditions on the refuel floor, (ii) the steam environment on the refuel floor, which would most likely set off area fire alarms, and (iii) the area radiation monitors on the refuel floor, which would indicate higher radiation levels as reactor vessel levels lowered and likely result in alarm and isolation signals Following the event, CENG evaluated other NMP operations crews during simulator training exercises to see if they would identify the loss of SDC in a timely manner given the same indications and without their prior knowledge of the sequence of events. Each crew succeeded in identifying the loss of SDC within 4 minutes.
2. If the ROs could not have restored SDC as occurred during the event, there were multiple other means to provide additional inventory makeup to the reactor:
a. At the time of the event, reactor level was being maintained by balancing condensate system makeup and reactor cleanup system letdown, and both of these systems remained in service throughout the event and could be remotely operated from the Control Room. The RO monitoring reactor level was briefed and authorized to adjust make up and letdown flow as necessary to maintain reactor vessel level.
b. The control rod drive system was available to provide reactor make-up and could be manually started from the Control Room.
c. The core spray (CS) system was considered available (although technically inoperable) and could have been restored to operability and used within 15 Enclosure 1
minutes by restoring air to two air operated valves and opening those valves (and personnel were staged in the plant and available to perform those actions).
CENG also noted that, because the event occurred during an outage, there were additional operators available, well above the minimum staffing required by Technical Specifications, (seven licensed ROs and seven licensed Senior ROs) who were in the Control Room, the Outage Control Center, and in the plant supervising work activities, and could aid in any of the recovery actions. These additional resources were not credited in the NRC risk assessment model.
Additionally, CENG presented its view that the NRC risk assessment, which applied a cutoff value for human error probabilities of 1E-6, was inappropriately conservative for this scenario and was the primary reason the preliminary significance determination outcome was greater than Green. The NRC staff performs risk assessments of inspection findings and reactor incidents to determine their significance for appropriate regulatory response. Current NRC risk analysis guidance limits the combination of human error probabilities to a chance of one in a million (1E-6). The guidance was written for operational plant conditions, involving minimum crew staffing, and a limited time frame for diagnosis and completion of human actions. The limit of one failure in a million opportunities was put in place to ensure human error cannot be statistically disregarded by multiplying multiple human error factors together and getting an unrealistically low probability of failure. CENG stated, in part, in its presentation that the 1E-6 limit was inappropriate in this scenario due to the availability of multiple redundant cues, presence of additional licensed operators, the nature of the anticipated operator actions to restore SDC or provide makeup inventory to the reactor, and the amount of time available.
CENG further offered that the assumption in the NRC risk assessment that the time from core uncovery to core damage would be approximately two hours, was not supported by the licensees computer modeling, which indicated there would be no appreciable radioactive release before 4.6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> from when a General Emergency was declared at core uncovery.
CENG commissioned an evacuation time estimate using NRC guidance and determined that the necessary evacuation activities could be effectively completed within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and 40 minutes.
Accordingly, CENG proposed that the NRC risk significance assessment should not be adjusted higher based on a Large Early Release Frequency.
During the conference, the NRC questioned CENG about whether the environmental affect of steam from the reactor cavity, which would occur if there were a delay in restoring a source of reactor coolant, could degrade the reactor building atmospheric conditions to the point where:
(a) the core spray system would not have been available and/or; (b) the reactor building ventilation system performance would have been impacted. CENG committed to provide a response to these questions following the conference, and this response was received via electronic mail on November 8, 2013 (ML13339A967).
a. Core Spray System Availability CENG determined that the CS system would remain available for injection under the postulated conditions (since the reactor head was de-tensioned and the vessel was vented to atmosphere, the worst case environment was conservatively assumed to Enclosure 1
be just over 200°F, 100% humidity, and at atmospheric pressure for both the drywell and reactor building). CENG compared the actual equipment qualification levels for CS equipment located within the reactor building (the CS pump and CS topping pump motors, the injection valve actuators, and the valve power supply breakers) to the conservatively assumed environment, and identified that the core spray equipment is qualified for high energy line breaks (HELBs) or loss of coolant accident (LOCA)
conditions that well exceed the assumed conditions. Since the core spray equipment is fully qualified for HELB and LOCA environments, it is reasonable to conclude that the system would have been capable of maintaining inventory under the postulated conditions should it have been required.
b. Reactor Building Ventilation System Performance CENG concluded that the reactor building ventilation system would have functioned as required, under the postulated conditions (with normal ventilation lost and with added LOCA heat loads and heat load contributions from the spent fuel pool). CENG used existing reactor building drawdown models / analysis, and determined refuel floor temperatures could reach 200°F with humidity assumed to be at 100%. The remaining reactor building elevation temperatures were determined to be significantly lower (ranging between 130°F and 160°F). The higher flow rates from the refuel floor biased the expected temperatures at the emergency ventilation system filters. Considering the expected heat transfer through the reactor building walls, condensation on the refuel floor, and the mixings from the lower reactor building elevations; the resultant temperature at the filtration units in the turbine building was calculated to be 170°F.
The filtration train is equipped with a 10KW heater designed to provide a minimum 15 degree temperature rise, which would reduce the humidity from 100% down to 75%,
which is well below the humidity level where decreased filtration efficiency can be expected (95%). The high efficiency particulate filters used by CENG are rated for 550°F and the charcoal filters are rated for 500°F. The system is also equipped with the ability to draw in cooler turbine building air if needed for filter train cooling. Based on the above, CENG concluded that the emergency ventilation system would have functioned to ensure a filtered, elevated discharge through the stack, and would have maintained refuel floor pressure well below that required to activate reactor building blow out panels.
Basis for NRC Conclusion The NRC staff evaluated the information developed during the inspection and the information CENG provided during the RC, and determined that the finding was of very low safety significance and, therefore, should be characterized as Green.
The NRC RASP Manual Volume 1 states, that risk analysts should not use a minimum joint HEP value of less than 1E-6. Similar to many numbers used in probabilistic risk assessment, the cutoff value is applied to maintain consistency and predictability of Reactor Oversight Process outcomes. However, the NRC RASP Manual Volume 1 also refers to EPRI 1021081, Establishing Minimum Acceptable Values for Probabilities of Human Failure Events: Practical Guidance for PRA, which states, that limits (like the 1E-6 value) should be adopted carefully and should be consistent within the context of the scenarios within which they are applied.
Therefore, it was incumbent upon the licensee to demonstrate why the application of the 1E-6 value was not appropriate in this case. After review, the staff agrees with CENG that many of the assumptions made in the NRC guidance limiting credit for independent human actions were more conservative then the specific details associated with this specific event. Therefore, the Enclosure 1
staff determined that applying a limit of 1E-6 is not an appropriate representation of the specific circumstances of this event. As documented in sensitivity analysis contained in Section 11 of the NRCs Preliminary Risk Assessment, applying a HEP limit of less than 1E-6 results in a conditional core damage probability of less than 1E-6, which corresponds to very low safety significance (Green).
The most significant factors in making this determination included:
1. Specific factors in this case that were not accounted for in the NRC risk assessment guidance, such as:
a. The relatively long amount of time operators had to diagnose the conditions and take actions to either restore shutdown cooling (4.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />) or inject to the reactor vessel (9 hours1.041667e-4 days <br />0.0025 hours <br />1.488095e-5 weeks <br />3.4245e-6 months <br />), which was a significantly greater timeframe than required for an event occurring when the reactor is at-power.
b. The large number of licensed operators monitoring plant operations. Fourteen licensed operators, in both the Control Room and Outage Control Center and the fact a crew turnover would occur significantly reduce the likelihood of an error in diagnosis of the event.
c. The number of workers and other means of monitoring radiological and environmental conditions on the refuel floor.
2. The very high likelihood that such an event would have been identified and successfully mitigated. In particular, the NRC staff considered the following:
a. Reactor coolant temperature and reactor vessel level were designated and clearly marked as critical parameters, a dedicated Reactor Operator was assigned to monitor those critical parameters, and there were a significant number of redundant indications and alarms which would not have been affected by the loss of a DC bus.
b. Actions to restore shutdown cooling were appropriately preplanned, briefed, procedures were in place, and personnel designated and available. These actions are consistent with guidance for crediting temporary manual actions in place of an automatic action for system operability discussed in NRCs Part 9900, Technical Guidance, Appendix C, Specific Operability Issues, section C.5, Use of Temporary Manual Action in Place of Automatic Action in Support of Operability.
c. Multiple means to control level were available to the operators from the main control room [i.e. adjusting condensate system makeup flow, adjusting or securing letdown flow, and restoring the control rod drive system (by starting the pumps)] and the primary source of makeup flow (condensate) was in operation, unaffected by the loss of the DC bus and equipment is located outside of the reactor building.
Additionally, the staff reviewed CENGs response to the questions regarding any impacts from steam entering the reactor building, and concluded that it adequately addressed this concern.
Enclosure 1
Description of NRC Findings 1. Improper Bus Restoration Results in a Loss of Shutdown Cooling Introduction. The inspectors documented a violation of Unit 1 Technical Specification (TS) 6.4.1, Procedures, because Constellation Energy Nuclear Group (CENG) failed to properly restore from a loss of a vital direct current (DC) bus in accordance with station off-normal procedures resulting in an unplanned loss of all shutdown cooling (SDC)
when time to boil was less than 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />. Specifically, operators failed to recognize a potential for loss of SDC during battery bus 12 restoration in accordance with N1-SOP-47A.1, Loss of DC, Revision 00101, and N1-OP-47A, VDC Power System, Revision 02500.
Discussion. On April 15, 2013, Nine Mile Point (NMP) Unit 1 shut down for a refueling outage. On April 16th, the unit was in cold shutdown with the water level at the reactor flange. The reactor head vent piping had been removed and work was ongoing to detension the reactor vessel head. Simultaneous to this work, the station was conducting a scheduled test for Loss of Coolant Accident/Loss of Offsite Power (LOCA/LOOP). In addition, preparations were being made to start work on an electromatic relief valve (ERV) modification.
A contractor verifying the safety tagout on the ERV modification mistakenly went to the cabinet on the wrong division and opened the breaker cabinet door for the vital DC bus 12 (at 14:44). The vital 125 volt DC battery bus 12 cabinet door contains a mechanical interlock which opens battery breaker 12 and the static battery charger DC output breaker. The interlock de-energized the DC switchgear when the door was opened.
Upon opening the cabinet door and hearing breakers trip, the contractor realized he was in the incorrect cabinet and immediately contacted the control room. The loss of DC power generated an invalid SDC pump 12 high temperature pump breaker trip signal, but without DC control power the breaker did not trip and the pump continued to run and provide SDC to the core.
Operators failed to recognize the invalid 12 SDC Pump trip signal present on the alarm log and the plant process computer displays prior to attempting to restore battery bus 12.
The presence of the trip signal was also indicated by a control room annunciator which was locked in since the loss of battery bus 12 at 14:45.
Two unsuccessful attempts were made by Operations to re-energize the bus at 15:03 and 15:05 by closing battery breaker 12. A third attempt was initiated at 15:46 utilizing a different method, which used battery charger 171. This momentarily energized the battery bus system allowing the previously created SDC pump trip signal to trip the running SDC pump 12. The battery bus then tripped again leaving the system de-energized. Per the licensees time line, the operator at the controls took only four minutes to identify the loss of SDC although there were no additional alarms received when the pump tripped. The operator identified the loss of SDC upon observing that reactor building closed cooling (RBCLC) temperature was lowering unexpectedly.
RBCLC is the heat sink for the SDC heat exchanger and RBCLC temperature was lowering because no heat was being transferred from the SDC system to the RBCLC system since there was no SDC flow.
Enclosure 2
The operators restored SDC by racking in the breakers for SDC pumps 11 and 13 and starting those pumps. SDC flow was restored at 16:17 when the SDC temperature control valve (38-09) was opened.
During this event there were no automatically initiated methods available to inject water into the core or restore SDC. Manual operator actions were required to restore SDC and to maintain reactor vessel level.
Analysis. The inspectors determined that the failure of CENG to establish an adequate procedure for properly restoring the battery bus 12 was a performance deficiency that was reasonably within CENGs ability to foresee and correct and should have been prevented. The performance deficiency was determined to be more than minor because the inspectors determined it affected the configuration control aspect of the Initiating Events cornerstone and adversely affected the associated cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, CENG failed to specify the associated tripping circuits and tripping actions that could result from battery bus restoration in accordance with N1-SOP-47A.1, Loss of DC, Revision 00101, and N1-OP-47A, VDC Power System, Revision 02500. This performance deficiency resulted in loss of SDC during attempted restoration of the vital DC battery bus 12 on April 16, 2013.
The inspectors evaluated the finding using Inspection Manual Chapter (IMC) 0609, Attachment 0609.04, Initial Characterization of Findings, issued June 19, 2012, and IMC 0609, Appendix G, Shutdown Operations Significance Determination Process, issued February 28, 2005. IMC 0609, Appendix G, Table 1, Losses of Control, states a quantitative analysis is required for:
Loss of Thermal Margin (PWRs and BWRs)
(Inadvertent change in reactor coolant system temperature due to loss of residual heat removal)/(change in temperature that would cause boiling) > 0.2 (temperature margin to boil)
In this case, RCS temperature changed 27 degrees (145°F to 118°F) and the change in temperature to boiling was 94 degrees (212°F to 118°F). Temperature margin to boil was greater than 0.2 (0.2872); thus, a quantitative analysis was required.
A phase III risk assessment was completed by NRC Senior Risk Analysts and .a preliminary greater than green finding and apparent violation letter, dated September 23, 2013, was issued (ML13266A237 - AV 05000220/2013003-04). A Regulatory Conference was held in the NRC Region I office in King of Prussia, Pennsylvania, on November 1, 2013, during which CENG was given an opportunity to provide additional information to be considered prior to issuing the final significance determination. On November 5, 2013, and again on November 19, 2013, Significance and Enforcement Review Boards (SERPs) were conducted to discuss the information provided during the regulatory conference. The SERPs concluded that, based upon the information provided during the Regulatory Conference and as discussed in the cover letter of this report, this finding was of very low safety significance (Green).
Enclosure 2
The inspectors determined this finding had a cross-cutting aspect in the area of Human Performance, Resources, because CENG did not ensure that personnel, equipment, procedures, and other resources were available and adequate to assure nuclear safety -
complete, accurate and up-to-date design documentation, procedures, and work packages, and correct labeling of components. Specifically, CENG procedures N1-SOP-47A.1 and N1-OP-47A did not contain adequate guidance to ensure recovery from a loss of a DC bus would not result in an unexpected plant transient H.2(c).
Enforcement. Unit 1 TS 6.4.1, Procedures, requires, in part, that written procedures and administrative policies shall be established, implemented, and maintained that cover the applicable procedures recommended in Regulatory Guide 1.33, Quality Assurance Program Requirements (Operation), Appendix A, Typical Procedures for Pressurized-Water Reactors and Boiling-Water Reactors, dated November 3, 1972. Regulatory Guide 1.33, Appendix A, Section 4, Procedure for Startup, Operation, and Shutdown of Safety-Related BWR Systems, requires procedures for onsite DC system, and Section 6, Procedures for Combating Emergencies and Other Significant Events, requires, in part, procedures for including loss of electrical power (and/or degraded power sources).
CENG procedures N1-OP-47A, 125 VDC Power System, Revision 02500, and N1-SOP-47A.1, Loss of DC, Revision 00101, implement this requirement.
Contrary to the above, as of April 16, 2013, NMP did not establish adequate procedures for the onsite DC system to include a loss of electrical power. Specifically, following the loss of a vital DC battery bus 12, operators attempted to restore power using implementing procedures N1-OP-47A and N1-SOP-47A.1. While those procedures indicated tripping circuits and tripping actions may be carried out when power is re-established, the procedures did not specify all of the affected components, including SDC pumps. As a result, when operators attempted to re-establish power, the site temporarily lost all SDC capability. Because this violation is of very low safety significance (Green) and CENG entered this issue into its corrective action program as CR-2013-002926 and CR-2013-002916, this violation is being treated as a non-cited violation (NCV) consistent with Section 2.3.2 of the NRC Enforcement Policy. (NCV 05000220/2013010-01, Improper Bus Restoration Results in a Loss of Shutdown Cooling)
Enclosure 2
2. Configuration Control error results in loss of a vital DC Bus Introduction. The inspectors documented a self-revealing Green finding of CENGs Conduct of Maintenance procedure, CNG-MN-1.01-1000, because CENG personnel failed to verify they were on the proper equipment prior to commencing maintenance activities. Additionally, Risk Management Activities recommended by CNG-OP-4.01-1000, Integrated Risk Management, such as temporary barriers and signs were not hung to for the protected #12 SDC train and vital 125 VDC battery bus to ensure workers did not assess protected equipment.
Description. Unit 1 shut down for a refueling outage on April 15, 2013. On April 16, Unit 1 was in cold shutdown at 118°F with a temperature band of 110°F to 120°F. The reactor vessel head was installed, and the head bolts were in the process of being detensioned in preparation for reactor cavity flood up and reactor vessel head removal.
Primary containment was open for planned maintenance. Decay heat removal was via the SDC pump 12. SDC pumps 11 and 13 were secured with their breakers racked out to the test position for planned LOOP/LOCA testing.
A risk assessment was completed in accordance with site procedure CNG-OP-4.01-1000, Integrated Risk Management, Revision 01300. As a result, the vital AC and DC buses associated with the ECCS train 12 and SDC train 12 were designated to be protected equipment and were listed as such on the Control Room operator logs and turnover sheets. However, additional risk management activities recommended by the procedure, such as hanging a sign on the room door, requiring workers to contact the Control Room prior to entry, and barriers around the switchboard designating the switchboard as protected equipment, were not put in place.
At 14:44 on April 16, a contractor walking down a tag-out associated with an ERV modification errantly entered the room for the incorrect train and, without verifying he was on the correct equipment, opened the breaker cabinet door for the vital DC battery bus 12. The vital DC battery bus 12 cabinet door contains a mechanical interlock which opens battery breaker 12 and the static battery charger DC output breaker, de-energizing the DC switchgear when the door is open. There is a sign on the cabinet door alerting works of this interlock, but the contractor did not read and understand the sign. Upon opening the breaker cabinet door and hearing the breakers trip, the contractor immediately contacted the control room and notified them of the event.
The loss of the vital DC battery bus 12 resulted in a partial loss of indication in the main control room, loss of DC control power for the associated bus, and a high-temperature trip signal for the SDC pump 12 being generated. However, since DC power to the trip solenoid was also lost, the SDC pump 12 continued to run. The emergency core cooling system (ECCS) pumps associated with the 12 train were rendered inoperable due to loss of control power; however, both trains ECCS were already declared inoperable since the injection valves for both trains of the core spray system are tagged shut and operating air is removed and the TS actions were already taken.
Analysis. The inspectors determined that CENGs failure to follow procedures which resulted in a loss of the vital DC battery bus 12 was a performance deficiency that was within CENGs ability to foresee and prevent. Specifically, a CENG contractor did not follow station procedures for control of maintenance by failing to verify he was on the proper equipment prior to commencing maintenance activities, and station personnel did Enclosure 2
not implement all risk management actions for protected equipment as directed by station risk management procedures. The performance deficiency was determined to be more than minor because the inspectors determined it affected the configuration control aspect of the Initiating Events cornerstone and adversely affected the associated cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations.
The inspectors evaluated the finding using IMC 0609, Attachment 0609.04, Initial Characterization of Findings, issued June 19, 2012, and IMC 0609, Appendix G, Shutdown Operations Significance Determination Process, Attachment 1, Checklist 5, BWR Hot Shutdown: Time to Boil < 2 Hours. A qualitative analysis is not required because the finding does not increase the likelihood that a loss of decay heat removal will occur due to failure of the system itself or support systems, the finding does not increase the likelihood of a loss of RCS inventory; the finding does not increase the likelihood of a LOOP or degrade the licensees ability to cope with a LOOP; the finding does not degrade the licensees ability to terminate a leak path or add RCS inventory when needed; the finding does not degrade the licensees ability to recover decay heat removal once it is lost; and the finding does not degrade the licensees ability to establish an alternate core cooling path if decay heat removal cannot be re-established for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Thus the finding screens to very low safety significance (Green).
The inspectors determined this finding had a cross-cutting aspect in the area of Human Performance, Work Practices, because CENG did not ensure that work practices support human performance. Human error prevention techniques, such as holding pre-job briefings, self- and peer-checking, and proper documentation of activities were not completed. Additionally, by not implementing the recommended risk management activities, a tool to ensure a more effective self-check by the worker was removed.
Enforcement. Enforcement action does not apply because this performance deficiency did not involve a violation of a regulatory requirement. The primary procedures, CENG procedures CNG-MN-1.01-1000, Conduct of Maintenance, Revision 00200 and CNG-OP-4.01-1000, Integrated Risk Management, Revision 01300 are not procedures required by NRC Regulatory Guide 1.33, Quality Assurance Program Requirements (Operation), Appendix A, Typical Procedures for Pressurized-Water Reactors and Boiling-Water Reactors, dated November 3, 1972. As such, they are not governed by the requirements of Unit 1 TS 6.4 Procedures. This issue was entered into CENGs corrective action program as CR-2013-002916. Because this performance deficiency does not involve a violation and is of very low safety significance, it is identified as a Finding. (FIN 05000220/2013010-02, Configuration Control error results in loss of a vital DC Bus)
Enclosure 2