IR 05000456/2005002
| ML051170499 | |
| Person / Time | |
|---|---|
| Site: | Braidwood  |
| Issue date: | 04/27/2005 |
| From: | Passehl D NRC/RGN-III/DRP/RPB3 |
| To: | Crane C Exelon Generation Co, Exelon Nuclear |
| References | |
| IR-05-002 | |
| Download: ML051170499 (14) | |
Text
ril 27, 2005
SUBJECT:
BRAIDWOOD STATION, UNITS 1 AND 2 NRC INTEGRATED INSPECTION REPORT 05000456/2005002; 05000457/2005002
Dear Mr. Crane:
On March 31, 2005, the U. S. Nuclear Regulatory Commission (NRC) completed an integrated inspection at your Braidwood Station, Units 1 and 2. The enclosed report documents the inspection findings which were discussed on April 7, 2005, with Mr. G. Boerschig and other members of your staff.
The inspection examined activities conducted under your license as they relate to safety and to compliance with the Commissions rules and regulations and with the conditions of your license.
The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.
Based on the results of this inspection, one NRC identified finding of very low safety significance was identified. This finding was determined not to involve a violation of NRC requirements.
In accordance with 10 CFR 2.390 of the NRCs Rules of Practice, a copy of this letter and its enclosure will be made available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRCs document system (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
Sincerely,
/RA/
Dave Passehl, Acting Chief Branch 3 Division of Reactor Projects Docket Nos. 50-456; 50-457 License Nos. NPF-72; NPF-77
Enclosure:
Inspection Report 05000456/2005002; 05000457/2005002 w/Attachment: Supplemental Information
REGION III==
Docket Nos: 50-456; 50-457 License Nos: NPF-72; NPF-77 Report No: 05000456/2005002; 05000457/2005002 Licensee: Exelon Generation Company, LLC Facility: Braidwood Station, Units 1 and 2 Location: 35100 S. Route 53 Suite 79 Braceville, IL 60407-9617 Dates: January 1 through March 31, 2005 Inspectors: S. Ray, Senior Resident Inspector N. Shah, Acting Senior Resident Inspector L. Haeg, Acting Resident Inspector C. Acosta Acevedo, Reactor Engineer D. Chyu, Reactor Inspector P. Lougheed, Senior Reactor Inspector T. Tongue, Project Engineer J. Roman, Illinois Emergency Management Agency Approved by: D. Passehl, Acting Chief Branch 3 Division of Reactor Projects Enclosure
SUMMARY OF FINDINGS
IR 05000456/2005002, 05000457/2005002; 01/01/2005 - 03/31/2005; Braidwood Station,
Units 1 & 2; Fire Protection.
This report covers a 3-month period of baseline resident inspection and an announced baseline inspection on heat sink performance. The inspection was conducted by resident inspectors and a regional engineering specialist. One Green finding was identified. This finding was determined not to involve a violation of NRC requirements. The significance of most findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP). Findings for which the SDP does not apply may be Green or be assigned a severity level after NRC management review. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 3, dated July 2000.
A. Inspector-Identified and Self-Revealed Findings
Cornerstone: Initiating Events
- Green.
A finding of very low safety significance was identified after the inspectors observed numerous fire hazards (i.e., poor control of combustible material and temporary power sources) during a walkdown of several non-safety related, abandoned buildings located inside the Protected Area. These conditions increased the potential for a loss of offsite power from an external fire, due to the proximity of the buildings to overhead 345 kV transmission lines and the Unit 2 safety related system auxiliary transformers. The primary cause of this finding was related to the cross cutting area of Human Performance (organization), because of the failure of licensee staff to follow station procedures for proper storage of transient combustible materials and use of temporary power sources.
This finding was considered more than minor, because of the potential for a loss of offsite power due to an external fire. This issue also affected the Mitigating Systems cornerstone objective to ensure that external factors (i.e., fire, flood, etc) do not impact the availability, reliability and capability of systems that respond to initiating events in order to prevent core damage. The finding was of very low safety significance because there was a reasonable potential for the licensee to identify and respond to a fire; additionally, if offsite power were lost, both Unit 2 emergency diesel generators were available and licensee control room staff were routinely trained in existing station procedures for addressing this event. No violation of NRC requirements occurred.
(Section 1R05)
Licensee-Identified Violations
No findings of significance were identified.
REPORT DETAILS
Summary of Plant Status
Unit 1 operated at or near full power for the entire inspection period.
Unit 2 operated at or near full power for the entire inspection period, except for a unit trip occurring on March 28, 2005. The trip was caused by a main generator trip-turbine trip due to the failure of a main generator output C phase bushing. An Unusual Event was declared at 1:59 p.m. on March 28, 2005 when a generator hydrogen leak was apparent. After isolation, the licensee terminated the Unusual Event at 4:23 p.m. on March 28, 2005. At the end of the inspection period, Unit 2 was in the process of ramping to full power following the March 28, 2005 trip.
REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity
1R01 Adverse Weather Protection
a. Inspection Scope
The inspectors verified that the licensee had taken the appropriate actions for a predicted winter storm, including the potential for icing and severe cold temperatures.
Specifically, the inspectors verified that the licensee had reviewed the impact of the weather against planned work activities, performed walkdowns of areas particularly susceptible to cold weather conditions and discussed weather related issues during the Operations Shift Turnover briefing and station Plan of the Day meetings.
The inspectors also reviewed the licensees specific actions to address apparent, recurring issues with switchyard breaker and control panel heaters. Specifically, the inspectors determined the low temperature limitations for the switchyard breaker and control panel instrumentation and confirmed these heater issues were being appropriately addressed. The inspectors also reviewed the licensees performance of weekly surveillance 0BwOS SY-W1, Unit Common Switchyard Surveillance, Revision 18, to determine whether other issues pertaining to cold weather concerns were being identified and tracked via the corrective actions program. This review constituted one sample of this inspection requirement.
Documents reviewed as part of this inspection are listed in the Attachment.
b. Findings
No findings of significance were identified.
1R04 Equipment Alignment
.1 Partial Walkdowns
a. Inspection Scope
The inspectors performed partial walkdowns of the accessible portions of risk-significant system trains during periods when the train was of increased importance due to redundant trains or other equipment being unavailable. The inspectors utilized the valve and electric breaker checklists listed to determine whether the components were properly positioned and that support systems were lined up as needed. The inspectors also examined the material condition of the components and observed operating parameters of equipment in an attempt to identify deficiencies. The inspectors reviewed outstanding Work Orders (WOs) and Condition Reports (CRs) associated with the train to determine whether those documents identified issues affecting train function. The inspectors used the information in the appropriate sections of the Technical Specification (TS) and the Updated Final Safety Analysis Report (UFSAR) to determine the functional requirements of the system. The inspectors also reviewed the licensees identification of and the controls over the redundant risk-related equipment required to remain in service.
In addition, the inspectors reviewed the adequacy of identification and resolution of the conditions listed in the Attachment.
The inspectors completed three samples of this requirement by walkdowns of the following trains:
- 1B safety injection system with the 1A safety injection train out of service for planned work;
- 2A essential service water (SX) system with the 2A SX train out of service for planned work; and
- Unit 2 electrical systems and protected equipment with Bus 9 and Line 0103 out-of-service for planned maintenance.
b. Findings
No findings of significance were identified.
.2 Complete Walkdowns
a. Inspection Scope
The inspectors performed a complete system walkdown of the Unit 1 main feedwater system. This system was selected because it is considered risk-significant from an initiating event standpoint. The system was also undergoing planned configuration changes to support planned maintenance and there was a potential for system mis-alignment.
In addition to the walkdown, the inspectors reviewed the following:
- selected operating procedures regarding main feedwater system configuration;
- CRs for the system initiated within the last year; and
- outstanding system WOs.
The inspectors also reviewed the CRs to determine whether issues were being properly addressed in the licensees corrective actions program. Documents reviewed as part of this inspection are listed in the Attachment. This walkdown represented one inspection sample.
b. Findings
No findings of significance were identified.
1R05 Fire Protection
.1 Quarterly Inspection
a. Inspection Scope
The inspectors conducted fire protection walkdowns which were focused on availability, accessibility, and the condition of fire fighting equipment, the control of transient combustibles and ignition sources, and on the condition and operating status of installed fire barriers. The inspectors selected fire areas for inspection based on their overall contribution to internal fire risk, as documented in the Individual Plant Examination of External Events with later additional insights or their potential to impact equipment which could initiate a plant transient. The inspectors used the Fire Protection Report, Revision 20, to determine: whether fire hoses and extinguishers were in their designated locations and available for immediate use; that fire detectors and sprinklers were unobstructed; that transient material loading was within the analyzed limits; and that fire doors, dampers, and penetration seals appeared to be in satisfactory condition.
The inspectors completed nine samples of this inspection requirements during the following walkdowns:
- Unit 1 and 2 halon protected areas;
- Unit 1 and 2 abandoned outbuildings;
- miscellaneous electrical equipment rooms, division 11 and 12;
- miscellaneous electrical equipment rooms, division 21 and 22;
- auxiliary building general area 426' elevation;
- lake screen house;
- fuel handling building;
- 2A safety injection pump room; and
- 2B safety injection pump room.
The inspectors verified that minor issues identified during the inspection were entered into the licensees corrective action program by reviewing the documents listed in the
.
b. Findings
Introduction:
A finding of very low safety significance (Green) was identified after the inspectors observed numerous fire hazards during a walkdown of several non-safety related, abandoned buildings located inside the Protected Area. These conditions increased the potential for a loss of offsite power from an external fire, due to the proximity of the buildings to overhead 345 kV transmission lines and the Unit 2 safety related system air transformers (SATs). Because the buildings were non-safety related, this finding was not considered a violation of regulatory requirements.
Description:
On February 14, 2005, the inspectors performed a walkdown of several non-safety related, abandoned buildings located inside the Protected Area. During the walkdown, the inspectors identified numerous examples where combustible/flammable materials were stored next to potential ignition sources. Some of these examples included combustible/flammable materials stored next to exposed, energized baseboard heaters, extension cords plugged in outlets - in both dry and wet conditions - without the use of a Ground Fault Circuit Interrupter, unattended and energized portable heaters and fans, and energized electrical cables having improperly secured, exposed ends adjacent to combustible/flammable material. These conditions were in violation of station expectations regarding the storage and control of combustible materials and the use of temporary power. These expectations were stated in the Exelon Nuclear Industrial Safety Pocket Guide (2005 edition) and in applicable station procedures for material housekeeping and electrical control.
These buildings were located below 345 kV power lines that supplied offsite power to Unit 2. In particular, the Vahledome building was located about 50 feet below these power lines and adjacent to the Unit 2 SATs. If a fire occurred in this building, the fire and smoke could cause a phase-to-phase fault in the overhead 345 kV lines and/or the SATs, causing a loss of offsite power to Unit 2. None of these buildings had automatic fire detection or suppression systems. Because the buildings were abandoned, they were also not periodically inspected by licensee staff.
Loss of offsite power events from external fires have occurred in the industry. On January 5, 1999, during a transformer fire at the Prairie Island Nuclear Plant, oil expelled from an explosion of the Unit 1 main transformer, ignited an adjacent area located underneath 161 kV lines supplying the Unit 1 reserve transformer. The smoke and flames from the oil fire caused a phase-to-phase fault between the B and C phases of the 161 kV lines, causing a lock-out of the reserve transformer and a loss of non-essential offsite power to Unit 1. This event was documented in Licensee Event Report 05000306/1999-01-00.
The licensee documented the inspectors observations in CRs 301231, 301264, and 301361. As discussed in these CRs, the licensee immediately removed all improperly stored flammable and combustible materials and de-energized all unnecessary plant equipment. Additional, long term actions included performing periodic walkdowns of these buildings and evaluating them for early demolition.
Analysis:
The inspectors determined that the failure to follow station procedures for the proper storage of transient combustible materials and use of temporary power sources was a performance deficiency warranting a significance evaluation in accordance with Inspection Manual Chapter (IMC) 0612, Power Reactor Inspection Reports, Appendix B, Issue Disposition Screening, issued June 20, 2003. This finding was considered more than minor, because it could be reasonably viewed as a precursor to a significant event, specifically a loss of offsite power due to an external fire. This issue also affected the Mitigating Systems cornerstone objective to ensure that external factors (i.e., fire, flood, etc) do not impact the availability, reliability and capability of systems that respond to initiating events in order to prevent core damage. The inspectors determined that this event affected the cross-cutting area of Human Performance, because of the failure of licensee staff to follow station procedures.
The inspectors performed a significance determination of this issue, using IMC 0609, Significance Determination Process, dated March 21, 2003, Appendix F, Fire Determination Significance Determination Process, dated May 28, 2004.
As stated, the failure to follow station procedures for the proper storage of transient combustible materials and use of temporary power sources was a performance deficiency that was considered more than minor. This met the Phase I qualitative screening criteria as discussed in Appendix F. Per step 1.1 of this Appendix, the inspectors determined that this finding affected the category of Fire Prevention and Administrative Controls, in that, combustible material was not being properly controlled in these abandoned buildings.
Per step 1.2, of Appendix F, the inspectors determined that this finding had a Low degradation rating. Although these buildings were unoccupied and did not have automatic fire suppression or detection systems, the outside general area was well trafficked by licensee staff and a fire would likely be noticed and reported to the main control room. Given the 50 foot clearance between the 345 kV power lines and the buildings, there was time for both onsite and offsite fire response. In the event that offsite power were lost, both Unit 2 emergency diesel generators were available and licensee control room staff were routinely trained in existing station procedures for addressing this event. Therefore, per step 1.3 of Appendix F, the inspectors concluded that this finding was likely of very low safety significance (Green) (FIN 05000456/2005002-01; 05000457/2005002-01). The inspectors discussed this issue with a Region III fire protection specialist and a Senior Reactor Analyst; both individuals agreed with the inspectors conclusions.
Enforcement:
The inspectors concluded that no violation of regulatory requirements had occurred as the abandoned buildings were not considered safety-related. As stated, the licensee entered the inspectors observations into its Corrective Action Program.
.2 Annual Fire Brigade Drill
a. Inspection Scope
The inspectors observed the licensees response to a simulated fire inside the abandoned Vahledome Building. This building was located inside the Protected Area, but outside the auxiliary and turbine buildings. The inspectors chose this scenario because it was conducted outside of normal shift hours, the Vahledome Building was located adjacent to the Unit 2 transformer yard, a highly risk significant area, and the drill involved the simulated recovery of an injured individual. Prior to the drill, the inspectors performed a walkdown of the simulation with the Fire Marshall to identify the specific hazards and drill objectives to be addressed by the fire brigade. Because there were no fire equipment cages in the area, the inspectors also observed the licensees controls for bringing in fire fighting equipment from the turbine building fire cages. During the drill, the inspectors observed the following specific aspects of the fire brigade response:
- the fire brigade responded in a timely manner;
- the protective equipment was in good working order and was properly donned by the fire brigade;
- fire hoses were properly laid out, charged, and tested prior to entering the fire area of concern;
- fire fighting equipment was properly staged and used;
- the fire brigade leader had appropriate command and control and had good radio communication with the responders and the control room; and
- the brigade members used appropriate search and rescue and recovery methods to remove the injured individual from the fire.
The inspectors also attended the post-drill critique to determine whether the pre-planned drill scenario was followed and whether the drill acceptance criteria was met.
Documents reviewed during this inspection are listed in the Attachment. This review constituted one sample of this inspection requirement.
b. Findings
No findings of significance were identified.
1R06 Flood Protection Measures
External Flooding Review
a. Inspection Scope
The inspectors performed an inspection of external flooding vulnerabilities and protective measures for the plant site, by performing a site walkdown and observing the condition of site flood mitigation features. The inspection consisted of a review of the external flooding design features described in the UFSAR and, in particular, whether changes to site structures were accounted for in the licensees external flooding analysis. The inspectors also verified that the licensee was entering issues into its corrective actions program. Those documents reviewed during this inspection are listed in the Attachment.
This review constituted one sample of this inspection requirement.
b. Findings
No findings of significance were identified.
1R07 Heat Sink Performance
Biennial Review of Heat Sink Performance
a. Inspection Scope
The inspectors reviewed the performance of the Unit 2 auxiliary feedwater (AF) system motor driven pump lube oil cooler and the diesel driven pump engine jacket water cooler and room cooler (a total of three heat exchangers). These heat exchangers were chosen for review based on their high risk assessment worth in the licensees probabilistic safety analysis. This review resulted in the completion of three inspection samples. While on-site, the inspectors reviewed completed surveillance tests, and associated calculations. The inspectors reviewed the documentation to confirm that the test and/or inspection methodology was consistent with accepted industry and scientific practices, based on review of heat transfer texts and an Electrical Power Research Institute standard NP-7552, Heat Exchanger Performance Monitoring Guidelines. The inspectors also reviewed documentation to verify that acceptance criteria were consistent with design basis values, as outlined in the updated final safety analysis report and TSs. The inspectors reviewed documentation to verify that the instruments were within calibration and discussed the use of the instruments with the system engineer to verify that the instruments were used correctly. The inspectors reviewed documentation to verify that the licensee took appropriate actions to verify physical integrity of the heat exchangers. The inspectors also reviewed documentation to verify that the licensee had appropriate controls in place to ensure availability of the ultimate heat sink under adverse conditions.
The inspectors reviewed corrective action documents concerning heat exchanger or heat sink performance issues to verify that the licensee had an appropriate threshold for identifying issues. The inspectors also evaluated the effectiveness of the corrective actions for identified issues, including the engineering justification for operability, if applicable.
The documents that were reviewed are included in the Attachment at the end of the report.
b. Findings
No findings of significance were identified.
1R11 Licensed Operator Requalification Program
Quarterly Review of Testing/Training Activity
a. Inspection Scope
The inspectors observed the operating crew performance during evaluated simulator out-of-the-box scenario, Braidwood Station Licensed Operator Requalification Simulator Scenario Guide 0511, Steam Line Break/Update Final Safety Analysis Report Timing Scenario, Revision 0.
The inspectors evaluated crew performance in the following areas:
- clarity and formality of communications;
- ability to take timely actions in the safe direction;
- prioritization, interpretation, and verification of alarms;
- procedure use;
- control board manipulations;
- oversight and direction from supervisors; and
- group dynamics.
Crew performance in these areas was compared to licensee management expectations and guidelines as presented in the following Exelon procedures.
The inspectors verified that the crew completed the critical tasks listed in the simulator guide. The inspectors also compared simulator configurations with actual control board configurations. For any weaknesses identified, the inspectors observed the licensee evaluators to determine whether they also noted the issues and discussed them in the critique at the end of the session. This review constituted one sample of this inspection requirement.
b. Findings
No findings of significance were identified.
1R12 Maintenance Effectiveness
Routine Inspection
a. Inspection Scope
The inspectors reviewed the licensees overall maintenance effectiveness for risk-significant event initiating, mitigating, and barrier integrity systems. This evaluation consisted of the following specific activities:
- observing the conduct of planned and emergent maintenance activities where possible;
- reviewing selected CRs, open WOs, and control room log entries in order to identify system deficiencies;
- reviewing licensee system monitoring and trend reports;
- attending various meetings throughout the inspection period where the status of maintenance rule activities was discussed;
- a partial walkdown of the selected system; and
- interviews with the appropriate system engineer.
The inspectors also reviewed whether the licensee properly implemented Maintenance Rule, 10 CFR 50.65, for the system. Specifically, the inspectors determined whether:
- the system was scoped in accordance with 10 CFR 50.65;
- performance problems constituted maintenance rule functional failures;
- the system had been assigned the proper safety significance classification;
- the system was properly classified as (a)(1) or (a)(2); and
- the goals and corrective actions for the system were appropriate.
The above aspects were evaluated using the maintenance rule program and other documents listed in the Attachment. The inspectors also verified that the licensee was appropriately tracking reliability and/or unavailability for the systems.
The inspectors completed three samples in this inspection requirement by reviewing the following systems:
- Units 1 and 2 main feedwater;
- Units 1 and 2 circulating water; and
- Units 1 and 2 instrument air.
Each of these systems were considered risk significant in the licensees probabilistic risk assessment model.
b. Findings
No findings of significance were identified.
1R13 Maintenance Risk Assessments and Emergent Work Control
a. Inspection Scope
The inspectors reviewed the licensees management of plant risk during emergent maintenance activities or during activities where more than one significant system or train was unavailable. The activities were chosen based on their potential impact on increasing the probability of an initiating event or impacting the operation of safety-significant equipment. The inspections were conducted to determine whether evaluation, planning, control, and performance of the work were done in a manner to reduce the risk and minimize the duration where practical, and that contingency plans were in place where appropriate.
The licensees daily configuration risk assessments records, observations of operator turnover and plan-of-the-day meetings, and observations of work in progress, were used by the inspectors to verify that the equipment configurations were properly listed, that protected equipment were identified and were being controlled where appropriate, that work was being conducted properly, and that significant aspects of plant risk were being communicated to the necessary personnel.
In addition, the inspectors reviewed selected issues that the licensee encountered during the activities, listed in the Attachment, to determine whether problems were being entered into the corrective action program with the appropriate characterization and significance.
The inspectors completed six samples by reviewing the following activities:
- troubleshooting of Unit 1 rod control system;
- emergent repair of 1B and 1C heater drain flash tank level control instrumentation;
- emergent repair of 2B emergency diesel generator jacket water pump and heater;
- unplanned loss of offsite electrical power feed from Davis Creek station to the Unit 2 switchyard;
- emergent repair of Unit 1 mini-purge containment isolation valve 1VQ005B; and
- emergent failure of the 1B reactor trip breaker.
b. Findings
No findings of significance were identified.
1R14 Operator Performance During Non-Routine Evolutions and Events
a. Inspection Scope
The inspectors completed three samples by observing the following events:
- failure and subsequent troubleshooting of the 1B reactor trip breaker during routine surveillance testing;
- failure and unplanned troubleshooting of the 1B emergency diesel generator during planned maintenance on the Unit 1 and 2 electrical cross-tie breaker ACB 1424; and
- the restart of Unit 2 following the March 28, 2005, reactor trip.
For each event, as applicable, the inspectors observed the control room response, interviewed plant operators and reviewed plant records including control room logs, operator turnovers, and CRs. The inspectors verified that the control room response was consistent with station procedures and determined whether identified discrepancies were captured in the corrective action program. Corrective action documents reviewed as part of this inspection are listed in the Attachment.
b. Findings
No findings of significance were identified.
1R15 Operability Evaluations
a. Inspection Scope
The inspectors evaluated plant conditions and selected CRs for risk-significant components and systems in which operability issues were questioned. These conditions were evaluated to determine whether the operability of components was justified. The inspectors compared the operability and design criteria in the appropriate section of the UFSAR to the licensees evaluations presented in the CRs and documents listed in the to verify that the components or systems were operable. The inspectors also conducted interviews with the appropriate licensee system engineers and conducted plant walkdowns, as necessary, to obtain further information regarding operability questions.
The inspectors completed six samples by reviewing the following operability evaluations and conditions:
- CR 289030, Service Water Flow to Emergency Core Cooling System Cubicle Cooler Decreased During 1BwOS CC-2," dated January 9, 2003;
- CR 291106, 2B Diesel Generator Jacket Water Pump trips, dated January 15, 2005;
- CR 291377,Operability Concerns with a Unit Component Cooling Water Heat Exchanger Isolated, dated January 17, 2005;
- CR 304792, Component Cooling Temperature Less than Its Required 60 degrees F, dated February 23, 2005;
- CR 289252, Long-Standing Plant Barriers Impaired (PBIs > 1 Yr Old), dated January 10, 2005; and
- CR 301744, Design of Refueling Water Storage Tank Vacuum Relief System, dated February 10, 2005.
b. Findings
No findings of significance were identified.
1R16 Operator Workarounds
a. Inspection Scope
The inspectors conducted reviews of plant conditions and documents to determine whether there were any issues that should have been evaluated and tracked as an operator work-around. The inspectors attempted to find conditions that could increase the potential for personnel errors or that would require compensatory actions to operate equipment during transients or events. The inspectors used the guidance in station procedure OP-AA-102-103, Operator Work-Around Program, Revision 1, to identify potential operator work-arounds.
The inspectors completed two samples by conducting the following reviews:
- manual level control of 1C heater drain flash tank; and
- recurrent issues with Unit 2 power range deviation alarms The inspectors determined whether these issues were entered into the licensees Corrective Actions Program and whether corrective actions were being appropriately developed. Documents reviewed as part of this inspection are listed in the Attachment.
b. Findings
No findings of significance were identified.
1R17 Permanent Plant Modifications
Annual Review The inspectors reviewed and evaluated the licensees 10 CFR Part 50.59 screening form number BWR-S-2005-31 to change the individual Local Leakage Rate Test acceptance criterion for the Unit 1 and 2 containment mini-purge penetrations VQ003, VQ004A/B, and VQ005A/B/C. This change maintained an administrative warning limit that was equal to the original acceptance criteria.
The inspectors reviewed the acceptance criteria against the licensees overall containment leakage acceptance criteria to verify that the changes did not adversely impact TS and design basis requirements. The inspectors also verified that the change did not introduce any new system vulnerabilities. In addition, the inspectors reviewed the licensees previous Local Leakage Rate Test summation results of Type B & C tests conducted as required by 10 CFR Part 50, Appendix J. Documents reviewed as part of this inspection are listed in the Attachment. This activity constituted one inspection sample of the annual requirement.
b. Findings
No findings of significance were identified.
1R19 Post-Maintenance Testing
a. Inspection Scope
The inspectors reviewed post-maintenance testing activities associated with important mitigating systems, barrier integrity, and support systems to ensure that the testing adequately demonstrated system operability and functional capability. The inspectors used the appropriate sections of the TS and UFSAR, as well as the WOs for the work performed, to evaluate the scope of the maintenance and to determine whether the post-maintenance testing was performed adequately, demonstrated that the maintenance was successful, and that operability was restored. The inspectors determined whether the testing met the frequency requirements; that the tests were conducted in accordance with the procedures, including establishing the proper plant conditions and prerequisites; that the test acceptance criteria was met; and that the results of the tests were properly reviewed and recorded. The activities were selected based on their importance in demonstrating mitigating systems capability and barrier integrity. The inspectors verified that minor issues identified during the inspection were entered into the licensees corrective action program by reviewing the documents in the Attachment.
Six samples were completed by observing post-maintenance testing of the following components:
- surveillance testing of the security diesel generator;
- Unit 2 channel operational test of nuclear instrumentation system power range detector N41;
- 1A containment spray pump American Society of Mechanical Engineers (ASME)surveillance;
- 2A residual heat removal pump ASME surveillance;
- local leak rate testing of Unit 1 containment mini-purge isolation valve 1VQ005B.
b. Findings
No findings of significance were identified.
1R22 Surveillance Testing
a. Inspection Scope
The inspectors reviewed surveillance testing activities associated with important mitigating systems, barrier integrity, and support systems to ensure that the testing adequately demonstrated system operability and functional capability. The inspectors used the appropriate sections of the TS and UFSAR, as well as the WOs for the work performed, to evaluate the scope of the maintenance and to determine whether the surveillance testing was performed adequately, demonstrated that the maintenance was successful, and that operability was restored. The inspectors determined whether the testing met the frequency requirements; that the tests were conducted in accordance with the procedures, including establishing the proper plant conditions and prerequisites; that the test acceptance criteria was met; and that the results of the tests were properly reviewed and recorded. The activities were selected based on their importance in demonstrating mitigating systems capability and barrier integrity. The inspectors verified that minor issues identified during the inspection were entered into the licensees corrective action program by reviewing the documents in the Attachment.
Five samples were completed by observing and evaluating the following surveillance tests:
- 1A emergency diesel generator bypass of automatic trips;
- 2A emergency diesel generator monthly start and load;
- 1A emergency diesel generator hot restart;
- calibration of the main control room ventilation radiation monitors.
b. Findings
No findings of significance were identified.
1R23 Temporary Plant Modifications
a. Inspection Scope
The inspectors reviewed the following temporary modifications:
- installation of temporary level control instrumentation on the 1B and 1C heater drain flash tanks; and
- installation of freeze seal to 1A containment spray refueling water storage tanks recirculation line for check valve inspection.
For each modification, the inspectors reviewed the associated design change paperwork, attended applicable prejob briefings and observed installation and/or removal. The inspectors also reviewed contingency plans, as applicable, for modifications supporting continued component operability or reliability. The inspectors also verified that minor issues identified during the inspection were entered into the licensees corrective action program. This review constituted two samples of this inspection requirement.
Documents reviewed as part of this inspection are listed in the Attachment.
b. Findings
No findings of significance were identified.
Cornerstone: Emergency Preparedness
1EP6 Drill Evaluation
a. Inspection Scope
The inspectors observed licensee performance during an evaluated emergency response drill. The drill involved a simulated main steam line break without isolation.
Observations included operator response from the simulator, manning of the Technical Support Center, turnover of command and control to the Technical Support Center, and event classification and notification. Protective Action Recommendations were not part of the scenario scope and accordingly were not made. The inspectors confirmed that deficiencies noted during the drill, by either the inspectors or licensee evaluators, were entered into the licensees corrective action program. The inspectors also attended portions of the post drill critique for the Technical Support Center crew. Documents reviewed as part of this inspection are listed in the Attachment. This activity constituted one inspection sample.
b. Findings
No findings of significance were identified.
OTHER ACTIVITIES
Cornerstones: Mitigating Systems and Barrier Integrity
4OA2 Identification and Resolution of Problems
.1 Routine Review of Identification and Resolution of Problems
a. Inspection Scope
As discussed in previous sections of this report, the inspectors routinely reviewed issues during baseline inspection activities and plant status reviews to determine whether they were being entered into the licensees corrective action program at an appropriate threshold, that adequate attention was being given to timely corrective actions, and that adverse trends were identified and addressed. Minor issues entered into the licensees corrective action program as a result of the inspectors observations are generally denoted in the Attachment. These activities were part of normal inspection activities and were not considered separate samples.
b. Findings
No finding of significance were identified.
.2 Review of Licensee Refueling Outage Cause Evaluations (One Annual Sample)
Introduction During the previous two outages (A1R11 and A2R10) the inspectors identified a possible adverse trend associated with fuel handling and refueling activities. Identification of a possible trend was considered following two events during the October 2004 refueling outage for Unit 1 (A1R11). During fuel moves, the licensee took actions outside of procedures to free a bound fuel assembly that resulted in damage to an adjacent assembly (as discussed in NRC Inspection Report 05000456/2004008; 05000457/2004008). During reconstitution of the damaged assembly in the spent fuel pool, a stainless steel rod unexpectedly detached from a vendor tool resulting in the rod falling and becoming lodged in a stored assembly. It was determined that this tool was not fail-safe and that air was isolated to the tool allowing the rod to become unlatched.
There were no fission product releases or other adverse radiological consequences involved with these events.
The inspectors used the inspection guidance contained in Inspection Procedure 95001 as an aid to assess the adequacy of the licensees root cause analyses for these events.
In addition, the inspectors reviewed CRs (as found in the Attachment) generated during the last two outages to determine if any other adverse trends or possible precursors to the A1R11 events existed. Finally, the inspectors reviewed a common cause evaluation associated with licensee identified trending in Foreign Material Exclusion issues during refueling outages.
This inspection activity constituted one sample of this annual requirement.
a.
Effectiveness of Problem Identification and Cause Evaluation
- (1) Inspection Scope The root cause reports were reviewed to ensure that the root and contributing causes of issues were understood and that the extent of condition and extent of cause for the issues were identified. The inspectors conducted interviews with licensee staff involved with the analyses and evaluated the content of the reports against the requirements of the licensees Corrective Action Program Procedure LS-AA-125, Root Cause Analysis Manual LS-AA-125-1001, and 10 CFR 50, Appendix B.
- (2) Findings and Observations There were no significant findings identified associated with the licensees problem identification and cause evaluations. Overall, the licensee thoroughly evaluated identification, length of existence, and risk and compliance concerns associated with the issues. For each root cause report the licensee discussed circumstances surrounding the events through a detailed executive summary. Systematic evaluation methods were discussed and each identified causal factor, error precursor and contributing cause was described. In addition, extent of condition was reviewed and an assessment of risk was performed for each event to determine risk and consequence significance.
Several previous industry events were reviewed related to the fuel bumping event, most notably a Byron Station event which occurred in September 2003, where refueling machine interlocks were bypassed resulting in the machine mast contacting the rod control cluster assembly change fixture basket. The licensee considered the corrective action implementation from this event ineffective at Braidwood and a part of the inadequate training contributing cause to the A1R11 event. The licensee identified several previous industry events similar to the fuel bumping event, but no past operating experience was identified with respect to the stainless steel rod drop event.
Finally, the licensee addressed extent of condition for these events by verifying that no concurrent conditions existed and also instituted a fleet-wide review of fuel handling and fuel assembly reconstitution. In addition, the licensees vendor for fuel services performed an extent of condition review of their spent fuel pool tools to determine what other tools were not fail-safe.
b.
Effectiveness of Corrective Actions
- (1) Inspection Scope The root cause reports were reviewed to ensure that licensee corrective actions were sufficient to address the root and contributing causes, and to prevent recurrence by performance of effectiveness reviews.
- (2) Findings and Observations There were no significant findings identified associated with the licensees corrective actions. The inspectors determined that the licensee had either implemented final or interim corrective actions for each identified condition adverse to quality. Each corrective action affecting refueling activities at Byron were implemented before their March 2005 outage and all corrective actions were to be implemented at Braidwood before the April 2005 outage (A1R11). In addition, the inspectors verified that the licensee had a sufficient means of determining the effectiveness of the corrective actions by reviewing the Effectiveness Review Manual LS-AA-125-1004.
The inspectors questioned the fact that some spent fuel pool tools were identified by the vendor as being non-fail safe. The inspectors were concerned that even though corrective actions were taken to enhance training and procedures, the tool could still mechanically fail and that the event could reoccur. The licensee explained that as another measure, the Reactor Services program staff would require that all tools being used over irradiated fuel by vendors be of a fail-safe design.
4OA3 Event Followup
The inspectors completed three inspection samples in this area.
Licensee Event Report (LER) Review
.1 (Closed) LER 05000457/2004-002-00: Unit 2 Automatic Reactor Trip on 2C Steam
Generator Lo-Lo Level Initiated by a Failure of the Controlling Channel Steam Flow Card This event was discussed in Section 4OA3 of NRC Inspection Report 05000456/2004008; 05000457/2004008). The trip was caused by an erroneous, low steam flow signal generated by a failed circuit card. Operator actions were unable to recover the steam generator level before the reactor trip. The licensee determined that the circuit card failed from age related degradation. This event was captured in the licensees Corrective Action Program as CR 285216.
During the investigation of this event, the licensee identified a significant difference in the response of the Unit 1 and Unit 2 feedwater control logic. Specifically, on low steam generator water level, Unit 2 had a much faster speed reduction of the feedwater pumps and the feedwater regulating valve had a much slower response to reopen. This meant that operators were less likely to recover from a low steam generator water event on Unit 2 than on Unit 1. The reason for the difference was due to changes the licensee made to the Unit 2 control settings between 1987 and 1993. Originally, the settings were established consistent with guidance from the nuclear steam supply vendor, Westinghouse, during the Unit 2 initial startup. Subsequently, the licensee changed the controller settings based on operating experience from the initial startup of Byron Unit 2, and in 1993, in support of a Braidwood and Byron station standardization of the Instrument Test Packages. The affect of these changes on the Unit 2 operator response were not apparent until the December 2004 reactor trip.
The inspectors concluded that this event did not result from a performance deficiency and therefore was not considered a finding. The inspectors noted that the proposed corrective actions for this event were reasonable. These actions included, but were not limited to, reviewing the preventive maintenance program for the circuit cards, discussing the difference in Unit 1 and 2 feedwater control response with the operators, and evaluating the appropriateness of the Unit 2 feedwater controller settings. This LER is considered closed.
.2 (Closed) LER 05000457/2005-001-00: Incorrect Installation of Flow Element Resulted in
Service Water Flow Below the TS Limit On January 11, 2005, the licensee discovered that the 2A reactor containment fan cooler (RCFC) annubar flow instrument was installed backwards. This condition was determined to exist since original construction. This condition was identified when the instruments were being inspected and cleaned as part of a scheduled work order. With the annubar installed backwards, the licensee determined that the SX flow to the RCFC was potentially lower than the 2660 gallons per minute (gpm) required by TS 3.6.6.3.
This was determined by looking at three years worth of surveillance data and adjusting the indicated (falsely high) values to correspond with bounding inaccuracies associated with the instrument installed backwards. The lowest actual SX flow was determined to be 2587 gpm (73 gpm lower than the TS limit).
The inspectors determined that the reduction in SX flow reduced the heat removal capacity of the 2A RCFC by only a small fraction. This reduction in thermal performance was well within the design basis heat removal requirements as stated in the UFSAR. As a corrective action, all other RCFCs at Braidwood Unit 1 and Unit 2 were inspected and no discrepancies were found.
The inspectors concluded that this issue was a performance deficiency, as the annubars have a stamped, exterior arrow indicating the proper direction of flow. Therefore, the licensee could have reasonably observed the improper alignment following initial installation and during subsequent, routine walkdowns and surveillance testing.
Because the thermal performance of the 2A RCFC was not significantly affected, the inspectors answered No to all four minor questions addressed in IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Disposition Screening, issued June 20, 2003. However, because the TS required minimum flow rate was not met, this event is considered a violation of minor significance that is not subject to enforcement action in accordance with Section VI of the NRCs Enforcement Policy. The licensee documented the issues and corrective actions associated with this event in CR 290026. This LER is considered closed.
.3 Unit 2 Reactor Trip and Notice of Unusual Event
On March 28, 2005, Unit 2 tripped from 100% power due to a main turbine generator protective relay actuation. The actuation was due to a main generator neutral ground experienced when the generator C phase stator output bushing failed. The reactor trip was uncomplicated and all systems responded as designed. During the reactor trip response, the licensee observed an apparent hydrogen leak into the turbine building from the unit 2 generator. The licensee evacuated personnel from the turbine building due to the apparent uncontrollable leak of flammable gas that could affect plant operations. Per the emergency plan, the licensee subsequently declared a Notice of Unusual Event and made the appropriate local, state and NRC notifications. The Unusual Event was terminated after the licensee isolated hydrogen flow to the generator and subsequently detected no measurable quantity of hydrogen in the turbine building atmosphere. The Unit 2 generator was brought back online April 1, 2005.
The licensee captured the reactor trip in CR 318027 and initiated a prompt investigation to determine the cause of the bushing failure.
The investigation identified that the bushing failure was due to a sudden failure of a modified mechanical joint in the bushings bottom flange. This bushing was rebuilt and modified by a vendor prior to installation during Braidwoods Unit 2 refueling outage in November, 2003. The licensee determined that all other main generator bushings are original equipment and have not been modified beyond the initial design. The licensee plans to perform a root cause investigation for this event and will issue a Licensee Event Report.
b. Findings
No findings of significance were identified.
4OA4 Cross-Cutting Aspects of Findings
.1 A finding described in Section 1R05 of this report had, as its primary cause, a human
performance deficiency (organization), in that, the failure to maintain proper control over combustible material and temporary power sources resulted in an increased potential for a fire that could have resulted in a loss of offsite power to Unit 2.
4OA6 Meetings
.1 Exit Meeting
The inspectors presented the inspection results to Mr. G. Boerschig and other members of licensee management at the conclusion of the inspection on April 7, 2005. The inspectors asked the licensee whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified.
.2 Interim Exit Meetings
An interim exit meeting was conducted for:
- the results of the heat sink biennial inspection were presented to Mr. G. Boerschig and other members of licensee management at the conclusion of the inspection on February 4, 2005.
ATTACHMENT:
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee
- K. Polson, Site Vice President
G. Boerschig Plant Manager
- D. Ambler, Regulatory Assurance Manager
- R. Belair, Sr. Mechanical Engineer
- S. Butler, Licensing Engineer
- R. Clemens, Heat Exchanger Program Owner
- G. Dudek, Operations Director
- J. Eggart, Chemistry
- R. Gilbert, Nuclear Oversite Manager
- R. Himes, Engineering Programs Manager
- R. John, Nuclear Oversite
- T. Johnson, Reactor Vessel Project Manager
- J. Kuczynski, Chemistry Manager
- F. Lentine, Design Engineering Manager
- J. Moser, Radiation Protection Manager
- M. Prospero, Work Management Director
- R. Rabrig, Operations
- M. Sears, Steam Generator Program Owner
- M. Smith, Engineering Director
- B. Speek, Nuclear Oversite
- S. Stiles, Nuclear Oversite
- E. Wrigley, Maintenance Director
Nuclear Regulatory Commission
- D. Passehl, Acting Chief, Reactor Projects Branch 3
LIST OF ITEMS
OPENED, CLOSED AND DISCUSSED
Opened and Closed
- 05000456/2005002-01; FIN Poor Control of Combustible Material and Temporary
- 05000457/2005002-01 Power Sources
Closed
- 05000457/2004-002-00 LER Unit 2 Automatic Reactor Trip on 2C Steam Generator Lo-Lo Level Initiated by a Failure of the Controlling Channel Steam Flow Card
- 05000457/2005-001-00 LER Incorrect Installation of Flow Element Resulted in Service Water Flow Below the TS Limit Attachment
Discussed
None.
Attachment