IR 05000324/2007007

IR 05000324-2007-007, 05000325-2007-007, on 02/05/2007 - 02/23/2007, Brunswich Steam Electric Plant

ML070820476
Person / Time
Site:	Brunswick
Issue date:	03/23/2007
From:	Musser R A NRC/RGN-II/DRP/RPB4
To:	Scarola J Carolina Power & Light Co
References
IR-07-007
Download: ML070820476 (30)

Text

March 23, 2007

Carolina Power and Light CompanyATTN:Mr. James ScarolaVice PresidentBrunswick Steam Electric Plant P. O. Box 10429 Southport, NC 28461

SUBJECT: BRUNSWICK STEAM ELECTRIC PLANT - NRC PROBLEM IDENTIFICATIONAND RESOLUTION INSPECTION REPORT NOS. 05000324/2007007 AND 05000325/2007007

Dear Mr. Scarola:

On February 23, 2007, the US Nuclear Regulatory Commission (NRC) completed a teaminspection at your Brunswick Units 1 and 2 facilities. The enclosed report documents the inspection findings, which were discussed on February 23, 2007, with Mr. B. Waldrep and other members of your staff.The inspection was an examination of activities conducted under your license as they relate tothe identification and resolution of problems, and compliance with the Commission's rules and regulations and with the conditions of your license. Within these areas, the inspection involved examination of selected procedures and records, observations of activities, and interviews with personnel.On the basis of the sample selected for review, the team concluded that in general, problemswere adequately identified and evaluated, and effective corrective actions were implemented.

The thresholds for identifying and classifying issues were appropriately low; however, several instances were identified where adverse conditions were not adequately and timely evaluated and corrective actions were not implemented in a timely manner. Ineffective and incomplete corrective actions led to a number of repetitive problems that could have been prevented.

Corrective action program goals for completing evaluations and implementing corrective actions were sometimes not met because of competing priorities and lack of management enforcement of timeliness goals. This report documents one self-revealing finding that was evaluated under the significancedetermination process as having very low safety significance (Green). This finding was determined to involve a violation of NRC requirements. Additionally, a licensee-identified violation which was determined to be of very low safety significance is listed in this report.

However, because of the very low safety significance and because they are entered into your corrective action program, the NRC is treating these findings as non-cited violations (NCVs), in accordance with Section VI.A of the NRC's Enforcement Policy. If you contest these non-cited violations, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001; with copies to the Regional Administrator Region II; the CP&L2Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington,DC 20555-0001; and the NRC Resident Inspector at the Brunswick Steam Electric Plant.In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter and itsenclosure will be available electronically for public inspection in the NRC Public DocumentRoom or from the Publicly Available Records (PARS) component of NRC's 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/Randall A. Musser, Chief Reactor Projects Branch 4 Division of Reactor ProjectsDocket Nos.: 50-325, 50-324License Nos:DPR-71, DPR-62

Enclosure:

Inspection Report 05000325, 324/2007007

w/Attachment:

Supplemental Informationcc w/encl: (See page 3)

OFFICERII:DRPRII:DRPRII:DRPRII:DRSRII:DRPSIGNATURERAM forJDA by emailRAM forRAM forRAM forNAMEJZeilerJAustinJBaptistLCainSNinhDATE03/23/200703/23/200703/23/200703/23/200703/23/2007 E-MAIL COPY? YESNO YESNO YESNO YESNO YESNO YESNO YESNO CP&L3cc w/encl:Benjamin C. Waldrep Plant Manager Brunswick Steam Electric Plant Carolina Power & Light Company Electronic Mail DistributionJames W. Holt, ManagerPerformance Evaluation and Regulatory Affairs PEB 7 Carolina Power & Light Company Electronic Mail DistributionEdward T. O'Neil, ManagerTraining Carolina Power & Light Company Brunswick Steam Electric Plant Electronic Mail DistributionRandy C. Ivey, ManagerSupport Services Carolina Power & Light Company Brunswick Steam Electric Plant Electric Mail DistributionGarry D. Miller, ManagerLicense Renewal Progress Energy Electronic Mail DistributionAnnette H. Pope, SupervisorLicensing/Regulatory Programs Carolina Power and Light Company Electronic Mail DistributionDavid T. ConleyAssociate General Counsel - Legal Dept.

Progress Energy Service Company, LLC Electronic Mail Distribution James RossNuclear Energy Institute Electronic Mail DistributionJohn H. O'Neill, Jr.Shaw, Pittman, Potts & Trowbridge 2300 N. Street, NW Washington, DC 20037-1128Beverly Hall, Chief, RadiationProtection Section N. C. Department of Environment and Natural Resources Electronic Mail Distribution Peggy ForceAssistant Attorney General State of North Carolina Electronic Mail DistributionChairman of the North Carolina Utilities Commission c/o Sam Watson, Staff Attorney Electronic Mail DistributionRobert P. GruberExecutive Director Public Staff NCUC 4326 Mail Service Center Raleigh, NC 27699-4326Public Service CommissionState of South Carolina P. O. Box 11649 Columbia, SC 29211David R. SandiferBrunswick County Board of Commissioners P. O. Box 249 Bolivia, NC 28422Warren LeeEmergency Management Director New Hanover County Department of Emergency Management P. O. Box 1525 Wilmington, NC 28402-1525 CP&L4Report to James Scarola from Randall Musser dated March 23, 2007.Distribution w/encl

S. Bailey, NRR C. Evans (Part 72 Only)

L. Slack, RII EICS RIDSNRRDIRS OE Mail (email address if applicable)

PUBLIC EnclosureU. S. NUCLEAR REGULATORY COMMISSIONREGION IIDocket Nos:50-325, 50-324 License Nos:DPR-71, DPR-62 Report Nos:05000325/2007007 and 05000324/2007007 Licensee:Carolina Power and Light (CP&L)

Facility:Brunswick Steam Electric Plant, Units 1 & 2 Location:8470 River Road SESouthport, NC 28461Dates:February 5 - 9 and February 19 - 23, 2006 Inspectors:J. Zeiler, Senior Resident Inspector, V. C. Summer (Team Lead)J. Austin, Resident Inspector, Brunswick J. Baptist, Resident Inspector, Farley L. Cain, Senior Reactor Inspector, RII, Division of Reactor SafetyApproved by:Randall A. Musser, Chief Reactor Projects Branch 4 Division of Reactor Projects EnclosureEnclosure

SUMMARY OF FINDINGS

IR 05000325/2007007, 05000324/2007007; 02/05-09/2007, 02/19-23/2007; Brunswick SteamElectric Plant, Units 1 and 2; Biennial baseline inspection of the identification and resolution of problems. A non-cited violation (NCV) was identified in the area of ineffective and untimelycompletion of corrective actions.The inspection was conducted by a Senior Resident Inspector, two Resident Inspectors, and aSenior Reactor Inspector. One Green NCV was identified. 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 NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, "Reactor Oversight Process," Revision 3, dated July 2000.Identification and Resolution of ProblemsThe team concluded that in general, problems were adequately identified and evaluated, andeffective corrective actions were implemented. The team found that established thresholds for identifying and classifying issues were appropriately low. However, several instances were identified where adverse conditions were not adequately evaluated and corrective actions were not implemented in a timely manner to prevent recurrence of equipment related problems.

Corrective action program goals for completing evaluations and implementing corrective actions were sometimes not met because of competing priorities and lack of management enforcement of timeliness goals. One NCV was identified involving ineffective and untimely corrective actions associated with the failure of a conventional service water pump due to shaft corrosion. Operating experience was adequately evaluated for applicability to the plant, however, severalexamples were identified where external operating experience was not used effectively, such as with industry material corrosion controls, which resulted in service water pump and valve stem equipment failures prior to the implementation of appropriate preventive maintenance. The licensee's audits and self-assessments were effective at identifying issues and entering them into the corrective action program. These audits and assessments identified issues similar to those identified by the NRC with respect to repetitive significant equipment failures due in part to untimely and ineffective implementation of preventive maintenance. Based on discussions with licensee employees during the inspection, personnel felt free to report safety concerns.A.

Cornerstone: Mitigating Systems

Green.

A self-revealing, non-cited violation of 10CFR50, Appendix B, CriteriaXVI, "Corrective Action," was identified for the failure to take adequate corrective actions to prevent a failure of the 2C Conventional Service Water (CSW) pump on July 26, 2006, due to corrosion of the pump shaft coupling. Specifically, the 3EnclosureEnclosurelicensee failed to implement timely preventive maintenance to inspect thecondition of pump shaft based on previous indications of pump shaft corrosion.

The licensee entered the deficiency into their corrective action program as Action Request 201240 and completed inspections of the remaining pumps susceptible to similar corrosion.The finding is more than minor because it was associated with the equipmentperformance attribute of the mitigating systems cornerstone and affects the cornerstone objective of ensuring the availability of systems that respond to initiating events. The failure of the 2C CSW pump shaft coupling affected the availability of the CSW system. Using the Phase 1 worksheet in Manual Chapter 0609, "Significance Determination Process," the finding is determined to be of very low safety significance because it is not a design or qualification deficiency,does not result in an actual loss of service water safety function, and does not screen as potentially risk significant for external events. The contributing cause of this finding involved the appropriate and timely corrective actions aspect of the Problem Identification and Resolution cross-cutting cornerstone (4OA2.a.(3)(i)).

B. Licensee Identified Violations

A violation of very low safety significance, which was identified by the licensee, has beenreviewed by the inspectors. Corrective actions taken or planned by the licensee have been entered into the licensee's corrective action program. The violation is listed in Section 4OA7.

EnclosureEnclosure

REPORT DETAILS

4.OTHER ACTIVITIES (OA)4OA2Identification and Resolution of Problems a.Assessment of the Corrective Action Program (1)Inspection ScopeThe inspectors reviewed items selected across the seven NRC cornerstones of safety todetermine if problems were being properly identified, characterized, and entered into the corrective action program (CAP) for timely and complete evaluation and resolution. The inspectors reviewed in detail the licensee's CAP procedure, CAP-NGGC-200, "Corrective Action Program," Revision (Rev.) 19, which described the process for documenting and resolving issues via Nuclear Condition Reports (NCRs) that are tracked as Action Requests (ARs). The licensee's CAP procedure defines four priority action categories for significance screening of their NCRs. These categories included Priority 1 for significant adverse conditions, Priority 2 for adverse conditions of sufficient significance warranting apparent cause and corrective action, Priority 3 for adverse conditions of low significance that warrants only correcting and trending, and Priority 5 for adverse conditions that do not warrant fixing, but rather, can be enhanced, improved, or made more efficient. The inspectors selected and reviewed 155 NCRs initiated by the licensee from January 2005 to January 2007 (overlapping by approximately one-year with the last NRC baseline problem identification and resolution (PI&R) inspection conducted in December 2005). When necessary, the inspectors' reviews included NCRs older than January 2005 that were referenced by the original NCR sample set.

The inspectors selected representative samples from each of the four priority classifications. The reviews primarily focused on issues associated with eight risk-significant systems which included the emergency diesel generators (EDGs), EDG fuel oil, safety-related alternating current (AC) power distribution, 125 volt direct current (DC)power distribution, nuclear service water (NSW), residual heat removal service water (RHRSW), high pressure coolant injection (HPCI), and reactor core isolation cooling (RCIC). In order to confirm that NCRs were being initiated at a site-wide level, the inspectors selected a representative number of NCRs that were identified and assigned from the major plant departments including operations, maintenance, engineering, security, chemistry, and health physics. The inspectors' scope also included selected NCRs related to the findings included in NRC inspection reports and licensee event reports issued since the last PI&R inspection.The inspectors conducted walkdowns of components associated with the EDGs, AC/DCpower, NSW, RHRSW, HPCI, and RCIC systems to verify that problems had been properly identified and characterized in the CAP. System performance was reviewed by discussion with system engineers and by review of work requests (WRs) and completed maintenance work orders (WOs), maintenance rule data, and system health reports to 5EnclosureEnclosureverify that equipment deficiencies were being appropriately entered into the CAP. Control room operator logs for the month of June 2006 were reviewed to verify that NCRs were initiated for deficiencies described in the logs when appropriate. In addition, the inspectors attended plant morning status meetings and CAP initial review meetings to observe management oversight in the corrective action process.The inspectors reviewed seventeen selected industry operating experience items toverify that the items were appropriately evaluated for applicability and whether issues identified through these reviews were entered into the CAP. The inspectors reviewed licensee audits and self-assessments (focusing primarily on problem identification and resolution) to verify that findings were entered into the CAP and to verify that these findings were consistent with the NRC's assessment of the licensee's CAP.Documents reviewed are listed in the Attachment.

(2)AssessmentIdentification of Issues. The team determined that the licensee was effective atidentifying problems and entering them into the CAP. The threshold for entering issues into the CAP was appropriately low and employees were encouraged to initiate NCRs and WRs. NCRs reviewed as part of the selected samples were generally complete and accurate with some minor exceptions. Regarding equipment issues identified in the WR/WO system, the team noted that some groups were utilizing informal guidelines as criteria for entering these equipment deficiencies into the CAP database. In addition, the NRC identified a non-cited violation (2005010-02) in 2005 involving the failure to generate NCRs for abnormal conditions identified in WOs. However, based on the WRs/WOs reviewed by the team during this inspection, equipment deficiencies identified in WRs/WOs were appropriately entered into the CAP database.Based on the walkdowns of the eight plant systems selected for detailed review, theteam did not identify any new deficiencies that were not already captured in the CAP, which further illustrated the low threshold site culture that existed for identifying equipment related problems. Based on the review of operator logs, NCRs were appropriately initiated for identified deficiencies. For the audits and self-assessments reviewed, the inspectors verified that the issues raised were entered into the CAP for resolution.Prioritization and Evaluation of Issues. The team determined that problems wereadequately prioritized and entered into the CAP consistent with the licensee's CAP guidance. The team noted frequent extensions in completing evaluations, both for high priority classified items, as well as for less significant priority adverse conditions. The reasons documented for the majority of the extensions was "higher priority work activities." A high number of investigation extensions was a similar comment made during the previous NRC PI&R conducted in December 2005 and was also identified in licensee audits and self-assessments. The licensee's CAP Coordinator indicated that management was focusing greater attention in this area, as well as reducing the 6EnclosureEnclosurebacklog of "old" open CAP items. Based on the high number of extensions observed bythe team for 2006 generated NCRs, this area remained an area for improvement.In general, the licensee's evaluation of issues in the CAP were considered to beeffective. The technical adequacy and depth of evaluations was adequate, however, inconsistencies were noted in the quality of cause evaluations which in some cases, contributed to repetitive equipment failures due to inadequate evaluations and untimely corrective action implementation. Examples illustrating this problem included the following:*Repetitive Maintenance Rule Functional Failures of Vital and Non-Vital Lightingand Communications (L&C) Uninterruptible Power Supplies (UPSs): The vital UPS supplies 120 volt alternating current (VAC) uninterruptible power for components vital for continued plant operation, instrumentation for monitoring the status of the plant and for devices protecting major equipment in the plant.

The L&C UPS supplies 120 VAC uninterruptible power to control room and control building lighting and equipment, the public address system, and the security system. The team noted that a total of 46 documented functional failures have occurred since November 2004. All six UPS units are scoped within the Maintenance Rule and currently the Unit 1 L&C and Unit 2 "A" vital UPS units are (a)1 due to these repetitive failures. Both UPS systems have experienced multiple, repetitive functional failures of an intermittent nature resulting in a mostly momentary, but sometimes fixed or "hard," transfer of the UPS Inverter to the "alternate" source of power. During these transfers, the UPS power supply is no longer "uninterruptible" and represents a decrease in the reliability of the system to perform it's intended function.A total of four significant adverse condition, root cause evaluations werecompleted in response to the failures over a two year period. In all four cases the "actual" root cause of the intermittent transfers was not identified as a "potential" or "likely" cause to be investigated further. Several corrective maintenance actions involving multiple circuit card replacements, capacitor replacements, etc, were performed and proved to be ineffective in stopping the transfers. The team noted that seven of the NCRs documented separate failures were closed out with "no further investigation required," referencing intended corrective actions to be implemented as part of earlier root cause evaluations. However, at the time these statements were made, all corrective actions planned for the earlier root cause evaluation had already been completed. The licensee initiated an NCR to address this problem. Repetitive functional failures continued to occur from November 2004 to October 2006 on the Unit 1 L&C UPS with another functional failure, not related to the intermittent failures, occurring on October 19, 2006. Repetitive functional failures occurred on the 1A & 2A Vital UPS from March 2006 to August 2006. Subsequent troubleshooting in conjunction with vendor technical assistance revealed a physically damaged capacitor, located in the power supply of the L&C UPS, believed to be the root cause of the intermittent transfers. The Unit 2 Vital UPS experienced intermittent transfers until the UPS failed "hard" to the alternate 7EnclosureEnclosurepower source revealing a faulty "B" phase driver card. Based on the team'scomments, the licensee initiated NCR 221828 to document the untimeliness and evaluation weaknesses associated with the UPS problem resolution. The team concluded that since the 120 VAC UPS system is not safety-related equipment, no violation of Technical Specifications or other NRC requirement occurred.*Failure to Identify and Correct Degraded Containment Isolation Valve FollowingStroke Test Failure: On October 13, 2005, during Technical Specification required surveillance stroke testing of containment isolation valve 1-E41-F079 (HPCI Vacuum Breaker), the valve failed to stroke properly. While NCR 172901 was initiated for this problem, following limited troubleshooting involving the control switch circuitry checkout, the valve was successfully re-stroked and declared operable. On February 3, 2006, during the next scheduled quarterly Technical Specification surveillance test, the valve failed to stroke fully close again. At this time, the licensee initiated NCR 183102 and performed a formal root cause investigation. The stroke failures were ultimately found to be caused by severe pitting corrosion of the valve stem, an industry known issue with 410 stainless steel valve stems with graphitic packing material. Contributing to this problem was the lack of prior preventive maintenance to inspect the condition of this and other valve stems made of similar materials with original graphitic packing located in moist environments. The failure to adequately identify and correct the valve stem problem in October 2006 following the first stroke test failure was identified as a licensee identified non-cited violation and is discussedin Section

4OA7 of this report.In addition to the above mentioned more significant evaluation weaknesses, the teamidentified several negative observations involving NCRs that lacked thorough

investigations and minor documentation discrepancies. These issues included the following:*NCR 156964, Q-Class "B" Auxiliary Relays Should be Q-Class A" andEnvironmentally Qualified (EQ): The investigation identified that the cause was an "oversight" of the "EQ Re-Constitution" project, however, the extent of condition only documented the other three associated fan's relays as being considered and does not adequately address the mechanism (EQ Re-Constitution Project) which omitted these relays. The licensee generated NCR 223455 to investigate the adequacy of the extent of condition review.*NCR 183102, 1-E41-F79 Failure/HPCI Inoperability: The root cause evaluationidentified that there was previous external operating experience (EPRI-5697, etc.) related to pitting corrosion in stainless steel 410 with graphitic packing in a moisture environment, but did not investigate why the station had not addressed these in the past which could have allowed greater attention and possible discovery of the issue prior to failure.*NCR 209265, Water Found in Sensing lines for Unit 2 HPCI Exhaust DiaphragmSwitches: While it was considered that condensation from room temperature 8EnclosureEnclosuredifferences between the Residual Heat Removal and HPCI was the source of themoisture in the sensing lines, it was concluded that the source of water in sensing line was from a 2003 Unit 2 rupture disk failure event. The investigation was closed on November 10, 2006. A subsequent Unit 1 sensing line inspection on January 4, 2007 found a greater amount of water in the Unit 1 sensing line; however, no NCR was initiated or effort made to reconcile earlier conclusions with new information. The licensee initiated NCR 223054 to address the team's identification of this documentation inconsistency.*NCR 115446, RCIC Lube Oil Strainer High Differential Pressure: The teamnoted that actions to address this issue on Unit 2 (replace in-line pressure switch with replacement that has better reset function) were not effective in addressing this issue. In 2005, another high lube oil alarm occurred following the original problem. Actions were not undertaken to thoroughly understand nature of problem and differences in piping configurations associated with the Unit 1 and 2 RCIC lube oil systems. The team also noted that a corrective action item for replacing the pressure switch on both units was closed out in 115446 even though Unit 1 had not been replaced.*NCR 201240, 2C CSW Pump Failure: The root cause investigation identifies thefact that external operating experience (EPRI TR-106857-V12) was not incorporated into a maintenance plan and internal operating experience (System Engineer and Material Engineer observations/recommendations) was delayed almost two years. However, the team noted that the licensee's root cause investigation did not pursue why the external and internal operating experience information was not processed in accordance with expectations.*NCR 172856, WRT BNP Cooling Water Reliability Program Self-Assessment140541: This NCR was initiated to document a weakness in the cooling water reliability program basis document (0NEP-2704) because it excluded 70-30 Copper Nickel piping from continued inspections due to evidence that it was not susceptible to corrosion. While efforts were made to correct existing procedures and ensure that the corrosion issues were less likely to occur in the future, the team noted that the licensee's investigation did not pursue why the 70-30 Copper Nickel had not been originally included when internal and external operating experience indicated that plant service water piping was susceptible.*NCR 167802, EDG #4 Shutdown Interlock Valve Failure: On August 5, 2005, anair leak resulted from the failure of the shutdown interlock valve. Subsequent maintenance troubleshooting identified that the air start header pressure control valve had been installed backwards. The licensee's past operability evaluation determined that the engine would still have been capable of performing its intended function with the air leak. However, the team noted that the operability evaluation incorrectly assumed the pressure at the shutdown interlock valve was 100 psig versus 200 psig. The team questioned whether this difference in pressure could have an impact on the licensee's earlier evaluation. The licensee 9EnclosureEnclosureinitiated NCR 223261 to review the impact of this on their earlier evaluation. Ultimately, no operability concern was identified.Effectiveness of Corrective Actions. Overall, corrective actions developed andimplemented for problems were generally appropriate to the problem; however the team noted several examples where corrective actions were not implemented in a timely manner to prevent repetitive equipment failures. These examples are as follows:*On July 26, 2006, the 2C conventional service water (CSW) pump failed due to aseparated shaft at the lower pump to line shaft coupling and caused an auto-start of additional SW pumps. Licensee investigation into the cause identified corrosion and the absence of preventative maintenance as primary mechanisms by which the lower pump shaft coupling failed. Indications of pump shaft corrosion had existed since 1997 and efforts to inspect the pump shaft had been delayed prior to the pump failure. More specific details regarding this issue is discussed in Section 4OA2.a.(3)(i) of this report.*Between 2003 and 2007, four failures of various Allen Bradley 700DC Seriesrelays occurred that resulted in the inoperability of the emergency diesel generators. A corrective action to establish preventive maintenance (PM) routing documents for replacing specific relays was originally scheduled to be completed in May 2004 and was later extended until October 2005. Eventually the PM routing documents were completed in August 2005; however, prior to implementation of these PMs, subsequent relay failures occurred on April 10, 2005, and most recently, on February 19, 2007. More specific details of this issue is discussed in Section 4OA2.a.(3)(ii) of this report.In addition to the above mentioned significant conditions involving untimelyimplementation of corrective actions, the team identified several negative observations where the timeliness of corrective actions had been protracted or extended but did not represent an immediate safety concern. These issues included the following:*NCR 205787, Improvement Opportunity, identifies a longstanding equipmentissue the plant dealt with since 1993-1994 when new service water pumps were installed and it was discovered that four pumps had oversized impellers. The recommendation by the vendor was to run with the oversized impellers until 1996. The team noted that the 1996 overhaul of all service water pumps (to address corrosion issues) provided an opportunity to correct this issue, but no actions were taken and after assembly the licensee was unsure of which pumps had the incorrect impellers. The lack of a extensive PM program prevented additional opportunities to correct the impeller issue and the station developed a history of motor overheating problems on the service water pumps. These increased temperatures did not result in a system operability issue.*NCR 166500, Environmental Self-Assessment AR 145004145004Issue #1, was writtento address an April 2003 concern regarding underground fuel oil piping leaks. A previous NRC (NCR 89622) was initiated for not including fuel oil piping in the 10EnclosureEnclosureunderground piping integrity program. Subsequently, PM routing documents toperform pressure testing were not developed to ensure the piping was inspected a timely manner. Actions to pressure test underground fuel oil piping have been rescheduled 3 times ( ~18 months) due to "contingency planning" and synchronization with other WOs. Currently, one underground pipe has been successfully tested (August 2006) and the others are planned for mid-year 2007.*NCR 156020, Unit 2 Reactor Scram on April 9, 2005, developed long termcorrective actions to implement a plant modification (EC# 61014) to provide condensate pump flow indication and controls for throttling the condensate demineralizer bypass valve (CO-FV-49) in the Control Room. The lack of this valve control complicates the operator response to secondary plant stability control during transients. While this item is the oldest "operations work around,"

several plant transients have been complicated by this issue. The team noted that this modification has been rescheduled at least five times.

(3)Findings (i)Failure to Adequately Evaluate and Take Effective Corrective Action to Prevent Failureof 2C Conventional Service Water Pump Due to Pump Shaft Coupling CorrosionIntroduction. A Green self-revealing non-cited violation (NCV) of 10 CFR 50, AppendixB, Criterion XVI, "Corrective Action," was identified for the failure to take effective corrective action to prevent the July 26, 2006, failure of the 2C Conventional Service Water (CSW) pump.Description. The plant consists of ten safety-related Service Water (SW) pumps in aconfiguration that supplies both critical and non-critical cooling loads. The four Nuclear Service Water (NSW) pumps and six (CSW) pumps are designed to provide reliable sources of cooling water to vital plant loads during routine operations and in the event of a Design Basis Accident or transient. The SW pumps are submerged in a saltwater environment and the licensee has had a history of controlling corrosive attacks in this and other systems. The plant installed new SW pumps between the years of 1993 -

1994. In 1996, a dual unit shutdown was performed to examine the extent of condition that surrounded the corrosive failure of Monel bolting and subsequent failure of the 2A NSW pump. NCR 96-01016 was initiated to determine the root cause of the corrosion and implement actions to prevent recurrence. The root cause team determined that material evaluations were not intrusive enough to subsequently detect materials that would be susceptible to an environment where galvanic corrosion would occur. The affected components were replaced and NCR 96-01016 task item 14 required the inspection and evaluation of two SW pumps at 10 and 19 month intervals to determine if galvanic corrosion was still occurring. Inspection of the selected areas did not indicate that the galvanic corrosion mechanism was reoccurring and the task item was closed.

As part of the closure of task 14, conclusions were drawn that additional inspections would be planned at longer service intervals to verify that destructive mechanisms with longer initiation times would not degrade pump performance. The inspectors noted that 11EnclosureEnclosurethese inspections did not occur on submerged SW pump components prior to the 2CCSW pump failure on July 26, 2006.

In July 2002, NCR 64786 was written to address a continued issue with SW pump shaftpitting and corrosion. Licensee concerns about corrosion reappeared in 1997 when pitting corrosion was discovered on the 316 Stainless Steel stuffing box and packing gland of the 1A NSW pump. The licensee attributed this corrosion mechanism to saltwater spray and began monitoring and evaluating pitting corrosion on the SW pumps shafts above the packing. The licensee performed periodic inspections of the stuffing box and pump shafts and initiated work orders to replace installed packing with zero leakage packing. An enhancement item of NCR 64786 was to evaluate the SW pump shaft corrosion issues and develop a corrosion monitoring plan to address the issues. The corrosion monitoring plan evaluation was completed September 2002, and suggested that components above the packing continue to be periodically inspected and recommended that a baseline inspection be performed. The information gained from these activities was also classified as a precursor to the submerged section of the pump shaft because it was identified as less susceptible to this type of pitting corrosion. In February 2004, the SW System Engineer submitted a Preventative Maintenance Routing (PMR) to commence removal and rebuild of all SW pumps on a ten year frequency. These PMRs were not implemented but an alternative plan was developed to pull one SW pump and perform an inspection. This activity was delayed and did not occur prior to the failure of the 2C CSW pump on July 26, 2006.

On July 26, 2006, the 2B CSW pump auto started on low service water headerpressure. Local observation identified that the 2C CSW pump was making an abnormal noise and the 2C CSW pump was immediately stopped. The operators identified no change in header pressure and the licensee began an investigation for the apparent failure. NCR 201240 was written to document the pump failure and a root cause evaluation was performed by licensee and corporate staff. This root cause investigation determined that the 2C CSW pump coupling failed due to an axial split that originated from severe pitting. This pitting was caused by crevice corrosion, microbiological influenced corrosion (MIC), or a combination of the two in an aggressive corrosive environment. The absence of a PM program that was consistent with the timing defined by common industry SW materials inspection schedules was also determined to be a contributing cause to the pump failure. The inspectors reviewed the licensee's root cause evaluation associated with the 1996and 2006 events; conducted interviews with the root cause evaluation team members and system engineers; and reviewed associated work orders and NCRs. Based on the above, the inspectors agreed with the conclusions that the July 2006, 2C CSW pump shaft coupling failure was due to pitting corrosion and the lack of an effective Preventative Maintenance program. Historically, corrosion of components in a saltwater environment has been an industry wide issue that is not readily detectible using predictive maintenance vibration and performance monitoring. The licensee failed to properly utilize industry experience and internal lessons learned in a timely manner.

This delay in creating a program with broad enough inspection efforts to detect and 12EnclosureEnclosureprevent various types of corrosive attacks left the developing defects unnoticed untilfailure occurred.Analysis. The performance issue associated with this finding is that the licensee failed totake timely corrective action to prevent a failure of the 2C CSW pump originating from corrosive deterioration of submerged shaft components. Specifically, the licensee failed to fully evaluate and implement correct maintenance actions to detect and mitigate corrosive attacks associated with the failure of the 2C CSW pump to line shaft coupling on July 26, 2006. This finding is more than minor because it is associated with the Mitigating Systems cornerstone and affects the objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, because the degraded pump shaft couplingwas not corrected, the reliability of the 2C CSW pump was adversely affected. The inspectors evaluated this finding in accordance with IMC 0609, Appendix A, "Significance Determination of Reactor Inspection Findings for At-Power Situations." Aphase one evaluation determined that the performance deficiency was of very low safety significance because the abnormal conditions did not actually affect the safety system function of the service water system. The cause of the finding was determined to affect the cross-cutting aspect of the Problem Identification and Resolution cornerstone in that the licensee did not take appropriate and timely corrective actions to address safety issues and adverse trends.Enforcement. 10 CFR Part 50, Appendix B, Criterion XVI, "Corrective Action," requires,in part, that measures shall be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, deviations, defective material and equipment, and non-conformances are promptly identified and corrected. In the case of significant conditions adverse to quality, the measures shall assure that the cause of the condition is determined and corrective action taken to preclude repetition. Contrary to the above, following identification and documentation of corrosion on the SW pumps between 1997 - 2006, the licensee failed to fully evaluate and correct shaft coupling corrosion degradation that resulted in the 2C CSW pump failure that occurred on July 26, 2006. This issue has been entered in the licensee's corrective action program as NCR 201240. Corrective actions for this issue included inspecting and repairing the other SW pumps, establishing a preventative maintenance refurbishment program, and an evaluation of alternate materials for use in SW applications. This issue is being treated as a non-cited violation consistent with Section VI.A of the Enforcement Policy:

NCV 05000324/2007007-01, Failure to Adequately Evaluate and Correct Condition Adverse to Quality Resulting in 2C CSW Pump Failure.

(ii)Inadequate and Untimely Corrective Actions to Prevent Recurrence of EmergencyDiesel Generator Allen Bradley 700DC Series Relay FailuresThe inspectors noted weaknesses associated with the licensee's evaluations anduntimely corrective actions associated EDG Allen Bradley 700DC series relay failures.

The issues reviewed were from October 10, 2003, until the most recent failure that occurred during this inspection on February 19, 2007. It should be noted that on four separate occasions, the relay failures resulted in an EDG becoming inoperable or 13EnclosureEnclosurecontributed to additional unavailability time for repair. The following is a time line of theidentified relay issues and assessment of the licensee's corrective actions to address the issues:*NCR 108100 identified that EDG #4 became inoperable on October 19, 2003,due to a failed engine lube oil pressure trip (LPSCR) relay. The relay failed due to an internal electrical fault, which was subsequently characterized as a "common end of life" failure. The relay failed in a de-energized state which removed the low lube oil pressure trip function. The investigation identified other historical relay failures and failure modes. It was identified that the EDG #2 LPSCR relay had previously failed in a closed or energized condition, which would have kept an active trip in place. The investigation from this prior 2003 LPSCR relay failure inadequately concluded that the relay could only fail in the shelf state, resulting in a failure to consider more aggressive actions to address the failure. An evaluation was performed as part of NCR 108100 to identify which relays could potentially disable the EDGs, in the event of a failure. Two relays were identified, the ASCR-A/B relays. A corrective action item was generated to create PMs for periodic replacement of these relays. The inspectors determined that this earlier evaluation assumption error on the failure modes for the LPSCR relay contributed to untimely and ineffective actions to recognize the need for a relay replacement program prior to the October 2003 relay failure.*NCR 143328 documented the unexpected EDG #3 inoperability on November11, 2004. The investigation identified the Allen Bradley 700DC series ASCR-A relay coil had failed. The failure of the coil was obvious from a visual exam which noted melted insulation and a burnt smell. The inspectors noted that corrective actions from NCR 108100 to create PMs for relay replacements had been extended from May 2004 until October 2005. Again, had these PMs been implemented in a more timely manner, this may have precluded the relay failure that resulted in the November 2004 inoperability of EDG #3.*NCR 143797 was written on November 16, 2004, to document that a correctiveaction extension for implementing the relay PM replacement action as delineated in NCR 108100. An Enhancement item was created to consider PM routes to replace all normally energized and normally de-energized EDG Allen Bradley relays. This item was closed on December 15, 2005, without all critical relays being replaced.*NCR 156039 was initiated on April 10, 2005, to document the EDG #3 AllenBradley 700DC HLCR control relay coil failure that occurred on that date. The HLCR relay controls the shut off point of the EDG #3 fuel oil transfer pumps.

These pumps transfer fuel oil from the EDG #3 fuel oil storage tanks to the engine saddle tank. The NCR indicated that there was an ongoing effort to address the maintenance to be performed on these relays from actions from NCR 108100. Of the 30 700DC control relays per EDG, the population was divided into normally energized, normally de-energized, critical and non critical.

14EnclosureEnclosureA critical relay was defined as one that would cause the EDG to be inoperable ifit failed to energize (failed coil). The HLCR relay was not identified as critical, however the phrase "not critical but important enough to require some PM tasks," was applicable to this and all other non critical EDG control relays due to the impact on plant resources and resulting in EDG unavailability for repair. A corrective action to complete review of PM routing requests was due on September 8, 2005.*NCR 166409 was initiated on August 12, 2005, to perform a comprehensiveassessment of EDG system. The assessment included the verification of scope of existing NCR 108100 and NCR 143328. The conclusion was that, all corrective actions in NCR 108100 and 143328 were complete. All PM routing requests were generated to replace remaining relays.*NCR 223012 was initiated on February 19, 2007, to document that EDG #2tripped as a result of a lockout on low lube oil pressure. It was identified that the LPSCR Allen Bradley 700DC series relay had overheated and the contacts were wedged together in the energized state. The EDG is provided with circuitry to detect a low lube oil pressure condition and shutdown the EDG to minimize damage to engine components. The installed lube oil pressure switches sense this lack of lube oil pressure and complete an electrical circuit to the LPSCR relay through normally closed contacts. The LPSCR relay is energized continuously and is only de-energized when the engine is running and the engine-driven lube oil pump is in service pressurizing the lube oil header. While in the energized state a low lube oil pressure trip is active and following the 45 second time delay, from start initiation, the EDG tripped on a false low lube oil pressure signal. This same relay failure, although on a different EDG, was the subject of the October 2003 relay failure described in the aforementioned NCR

108100.The inspectors concluded that there have been multiple Allen Bradley 700DC SeriesRelay failures identified over the past four years and the licensee's corrective actions taken to date, have been either ineffective or untimely to prevent recurrence resulting in increased EDG inoperability and unavailability time. Pending further review of the licensee's investigation into the latest relay failure that occurred during this inspection on February 19, 2007, this issue is identified as Unresolved Item (URI) 05000325, 324/2007007-02, Repetitive Failures of EDG Allen Bradley 700DC Series Relays. b.Assessment of the Use of Operating Experience (1)Inspection ScopeThe inspectors examined licensee programs for reviewing industry operatingexperience, reviewed the licensee's operating experience database, and interviewed the Operating Experience Coordinator, to assess the effectiveness of how external and internal operating experience data was handled at the plant. In addition, the inspectors selected seventeen operating experience notification documents (NRC generic 15EnclosureEnclosurecommunications, 10 CFR Part 21 reports, licensee event reports, vendor notifications, and Progress Energy plant internal operating experience items, etc.), which had been issued since January 2005, to verify whether the licensee had appropriately evaluated each notification for applicability to the Brunswick plant. Documents reviewed are listed in the Attachment.

(2)AssessmentThe team determined that the licensee was effective in screening operating experiencefor applicability to the plant. The inspectors verified that the licensee had entered those items determined to be applicable into the CAP and taken adequate corrective actions to address the issues. External and Internal operating experience was adequately utilized and considered as part of formal root cause evaluations for supporting the development of lessons learned and corrective actions for CAP issues. During the inspection, the team noted several examples where root cause evaluations identified that operating experience was not effectively utilized that may have contributed to equipment problems, but subsequent actions were not taken to investigate and address why the operating experience had not been utilized.

(3)FindingsNo findings of significance were identified. c.Assessment of Self-Assessments and Audits (1)Inspection ScopeThe inspectors reviewed CAP trend reports, CAP backlogs, NCR trend reports,department self-assessments, and Nuclear Assessment Section audits to verify that the licensee appropriately prioritized and evaluated problems with the CAP in accordance with their risk significance. The inspectors compared the NRC's CAP assessment results against the licensee's assessment of the CAP effectiveness.

(2)AssessmentThe team determined that the scope of self-assessments and audits were adequate.Department self-assessments and Nuclear Assessment Section audits were generally self-critical and effective in identifying issues that were entered in the CAP for resolution.

Corrective actions developed as a result of these assessments and audits were generally effective. The team noted that Nuclear Assessment Section audit findings were being given the highest CAP process priority classification (Priority 1) and represented a large percentage of the total number of Priority 1 items being identified at the plant. The team noted that these audits and assessments identified issues similar to those identified by the NRC with respect to repetitive significant equipment failures due in part to untimely and ineffective implementation of preventive maintenance. It was been recognized that management had not yet established a long term strategy for improving equipment reliability.

16EnclosureEnclosure (3)FindingsNo findings of significance were identified. d.Assessment of Safety-Conscious Work Environment (1)Inspection ScopeDuring the reviews of selected NCRs, the inspectors conducted interviews withmembers of the plant staff including management, operations, maintenance, engineering, and CAP personnel, to develop a perspective of the safety-conscious work environment (SCWE) at the plant and the willingness of personnel to use the CAP and employee concerns program (ECP). The interviews were conducted to determine if any conditions existed that would cause employees to be reluctant to raise safety concerns.

Specifically, personnel were asked questions regarding any reluctance to initiate NCRsand the adequacy of the CAP/ECP for identified issues. The inspectors interviewed the ECP Coordinator and reviewed a select number of ECP reports completed in 2006 to verify that concerns were being properly reviewed and that identified deficiencies were being resolved in accordance with licensee procedure REG-NGGC-0001, "Employee Concerns Program." (2)AssessmentThe team concluded that licensee management emphasized the need for all employeesto identify and report problems using the CAP, ECP, and Work Order System. These methods were readily accessible to all employees. Based on discussions conducted with a sample of plant employees from various departments, the inspectors determined that the site staff felt free to raise issues and that management emphasized issues be placed into the CAP for resolution. The team did not identify any reluctance to report safety concerns.

(3)FindingsNo findings of significance were identified.4OA6Meetings, Including ExitExit Meeting SummaryOn February 23, 2007, the inspectors presented the inspection results to Mr. B. Waldrepand other members of his staff. The inspectors confirmed that proprietary information was not retained following the inspection.4OA7 Licensee Identified ViolationsThe following violation of very low safety significance (Green) was identified by thelicensee and is a violation of NRC requirements which met the criteria of Section VI of 17EnclosureEnclosurethe NRC Enforcement Policy, NUREG-1600, for disposition as a NCV.*10 CFR Part 50, Appendix B, Criterion XVI, "Corrective Action," requires, in part,that measures shall be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, deviations, defective material and equipment, and non-conformances are promptly identified and corrected.

Contrary to the above, following the Technical Specification surveillance stroke test failure of containment isolation valve, 1-E41-F079 (HPCI Vacuum Breaker)on October 13, 2005, the licensee failed to adequately investigate and determine the cause of the failure. Subsequently, the valve failed to stroke fully close again during surveillance testing on February 3, 2006. The failure was ultimately found to be caused by severe pitting corrosion of the valve stem, an industry known issue with 410 stainless steel valve stems with graphitic packing material.

Contributing to this problem was the lack of preventive maintenance to inspect valve stems in a moist environment and replace old graphitic valve packing. This finding is of very low safety significance because the opposite containment isolation valve remained functional during the period that valve 1-E41-F079 was degraded. This issue is documented in the licensee's corrective action program as NCR 183102.ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

G. Atkinson, Supervisor - Emergency Preparedness

L. Beller, Superintendent Operations Training

A. Brittain, Manager - Security

E. O'Neill, Manager - Training Manager

D. Griffith, Manager - Outage and Scheduling

L. Grzeck, Lead Engineer - Technical Support

S. Howard, Manager - Operations

R. Ivey, Manager - Site Support Services

T. Pearson, Supervisor - Operations Training

A. Pope, Supervisor - Licensing/Regulatory Programs

S. Rogers, Manager - Maintenance

J. Scarola, Site Vice President

T. Sherrill, Engineer - Technical Support

T. Trask, Manager - Engineering

J. Titrington, Manger - Nuclear Assessment Services

M. Turkal, Lead Engineer - Technical Support

M. Williams, Manager - Operations Support

B. Waldrep, Plant General Manager

NRC Personnel

Randall

A. Musser, Chief, Reactor Projects Branch 4, Division of Reactor Projects Region IIGene DiPaolo, Senior Resident Inspector

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened05000325, 324/2007007-02URIRepetitive Failures of EDG Allen Bradley 700DC SeriesRelays (Section 4OA2.a.(3)(ii))

Opened and Closed

05000324/2007007-01NCVFailure to Adequately Evaluate and Correct ConditionAdverse to Quality Resulting in 2C CSW Pump Failure

(Section 4OA2.a.(3)(i))

Closed

None.

A-2Attachment

Discussed

None.

Section 4OA2: Identification and Resolution of ProblemsProceduresCAP-NGGC-0200, Corrective Action Program, Rev.19CAP-NGGC-0201, Self Assessment and Benchmark Programs, Rev. 10

CAP-NGGC-0202, Operating Experience Program. Rev. 10

CAP-NGGC-0204, Human Performance Program, Rev. 0

CAP-NGGC-0205, Significant Adverse Condition Investigations, Rev. 5

CAP-NGGC-0206, Corrective Action Program Trending and Analysis, Rev. 1

OPS-NGGC-1305, Operability Determinations, Rev. 0

REG-NGGC-0001, Employee Concerns Program, Rev. 13

ADM-NGGC-0107, Equipment Reliability Process Guideline, Rev. 6

ADM-NGGC-0104, Work Management Program, Rev. 1

ADM-NGGC-0204, Work Management, Rev. 1

0OI-50.5, 120V UPS Bus 1-1A and 2-2A Electrical Load List, Rev. 19

2-PT-24.1-2, Service Water Pump and Discharge Valve Operability Test

1-PT-24.1-1, Service Water Pump and Discharge Valve Operability Test

SD-43, System Description, Service Water SystemNuclear Condition Reports147150, Multiple Repetitive UPS Functional Failures149888, U1 L&C UPS Swapped to Alternate Source on 1/09/2005

150957, U1 L&C UPS Failed to Hard Source

161304, U1 L&C UPS Functional Failure on 6/07/2005

166394, U1 L&C UPS Functional Failure on 6/07/2005

174554, U1 L&C UPS Momentary Transfers

184919, Additional U1 L&C UPS Momentary Transfers

187443, U1 L&C UPS Momentary Transfers

194720, U1 L&C UPS Functional Failure

197250, U1 L&C UPS Swapped to Alternate Source on 6/13/2005

198714, U1 L&C UPS Momentary Transfers on 6/28/06

199413, U1 L&C UPS Momentary Transfers on 7/6/06

201995, U1 L&C UPS Momentary Transfers on 7/28/06

203371, U1 L&C UPS Momentary Transfers on 8/15/06

205411, U1 L&C UPS Functional Failure on 9/04/06

206859, U1 L&C UPS Functional Failure on 9/17/06

208323, U1 L&C UPS Functional Failure on 10/02/06

209829, U1 L&C UPS Functional Failure on 10/19/06

186603, U1A Primary UPS Momentary Transfers on 3/06/06

187339, U2A Primary UPS Momentary Transfers on 3/11/06

188633, U2A Primary UPS Momentary Transfers on 3/19/06

190102, U2A Primary UPS Momentary Transfers on 3/22 & 23/06

A-3Attachment156964, Q-Class "B" Aux. Relay Should be Q-Class "A" and EQ156266, Repetitive MRFF 2-FW-FV-47 Air Operator Failure

155237, Ineffective Corrective Actions for Generator Sealant

155223, U2 Batteries Exceed MR Unavailability Criteria

154559, Loss of Power to Bus Common 'B'

154418, Inadequate Extent of Condition Assessment for CRB 46-43

2435, Repetitive MRFF of U2 Isophase Cooler

145757, Failure of Battery Charger 22B-1

139726, 480V Breaker Mag-Latch Failure

140705, BNP Response to Inverter Failures

161736, NAS Assessment B-EC-05-01-I1, NPDES Violation

214841, Service Water Pump Discharge Pressure Gages Not Calibrated

214843, Evaluation of Removed Gauges From PM Database

179631, Unit 2 MCPR Tech Spec Action Statement Entry

155030, Failure to Generate NCR in 2004

157075, Positive in processing Count for Individual at VC Summer

2848, Cathodic Protection Project

181433, Internal KPI for Rad Monitor Availability Not Met

156886, Service Water Radiation Monitor Inoperable

157295, Unplanned LCO Entry: SW Rad Monitor Inop

159042, Service Water Rad Monitor Spiking

161930, Unplanned LCO Entry - SW Effluent Rad Monitor

210690, Exceeded MR Criteria (FF) 2B NSW Pmp Motor Water in Oil

205691, Unplanned LCO entry Condition 2B NSW Pump

203878, 1C RHR Pump Seal Cooler Reduced Flow Rate

2664, Non Qualified Radworker Logged in on LHRA RWP

171082, Individual Entered into the RCA Without an ED

217954, HP not Promptly Notified of Dose Rate Alarm

2982, LHRA Door Found Ajar

186023, VHRA Lock Failed When Challenged

154718,

Increased Number of PCOs Attributed to Radworker Practices

170090, E&RC Self Assessment

140125 IFMC 2

194692, EDS With Low Batteries Handled Inappropriately

175685, PCM Alarm During Inprocessing

175177, Radworker Practices

170085, E&RC Self Assessment

140125 Weakness 2

171880, NRC PI Process Not Consistent With REG-NGGC-0009

176573, Missing Input/Basis Information From SW Hydraulic Analysis

176576, Calculation PCN G0050A-13 Discrepancy

170838, A Loop RHR SW Flow Instrument Piping

179544, Unit Two Vital Header Cross Tie Valve 2-SW-118

173923, Lack of

SW-V146 Operating Restriction and Analysis

204777, 2D RHRSW Pump Motor OTBD Bearing Temperature High LCO

151460, NSW Pump Start Logic

151378, Additional DG Load Calc,

BNP-E-7.010, Discrepancy

198054, Calculation Updates Needed Due to Vendor OE

209008, Missed MR Function Failure Found During MSPI Review

A-4Attachment155050, Limitorque Technical Updates156341, NRC IN 2005-010

179416, NRC Regulatory Issue Summary 2005-29 Anticipated Transients

183614, NRC Information Notice 2006-003 Motor Starter Failure

2883, Part 21 D.C. Cook EDG's FME From Manufacturer

207130, GE Safety Information Communication SC06-10

210583, Part 21 Potential For Frozen Displays OTEK Panel Monitoring

210587, NRC

IN 2006-22 Low Sulfur DG Fuel

210602, NRC

IN 2006-20 Foreign Material in ECCS

215554, Operation of Reactor in Unanalyzed Region

166387, NRC

IN 2005-24 Nonconservatisms in Leakage Detection

2949, Nuclear Power Plant Maintenance

200682, Tech Bulletin

TB-06-10 Reference AR 183614183614: 211962, Service Water Piping Degradation

169612, Plant Start Up Reactor Level

204899, NRC

IN 2006-15 Vibration Induced Degradation Valves

153894, Hatch Safety Relief Valve Tee Quencher Support Bolts

215818,

SA 177826 W-1, Lack of CCW Coordination Meetings

53006, Conduct a Self Assessment of the CCW Chemistry Program

137098, 1B NSW Pump Inop

154921, Contamination Found on Individual During Inprocessing at ANO

88981, RHR Pump Seal Cooler Low Flow Alarm

170082, E&RC Self Assessment

140125 Weakness 1

159730, Functional Failure of 2-SW-FS-114

2856, Self Assessment

140541 Weakness #1 Cooling Water Reliability

197037, 1B CSW Pump Exceeds 14 Day Impairment

195803, 1B CSW Pump Stator Exceeded 315 Degrees

195140, 1B CSW Stator Temp on PPC Reading 300F

204543, 1C CSW Pump Elevated Motor Temperature

205787, Improvement Opportunity

201596, Service Water Pump Operability Determination

203906, Lower Bearing Damage on 1C CSW Pump Bowl

214876, 1A CSW Pump DP Within Alert Range

118773, PMR 2C CSW Pump 10 Year Rebuild

64786, SW Pump Shaft Pitting/ Corrosion

91863, Need New PM Routes For U/1 & 2 Conv and Nuc Pmp Shaft Insp

96-01016, Root Cause Analysis for 2A NSW Pump Trip

166500, Environmental Self Assessment

AR 145004145004Issue #1

89622, Fuel Oil in The AOG Building

97766, Self Assessment 77469-26 W#1 Buried Piping

91903, DG#3 Right Bank Air Distributor Drift

103112, DG Temperature Switches Mounted Incorrectly

105988, Declining Trend in DG Collector Ring Megohm Ready

108100, DG#4 Inoperable Due to Failed LPSCR Relay

29965, DG2 Jacket Water Cooler Outlet Flange Stud Corrosion

141927, ZTEF Critical Component Pm Consideration

143328, Unexpected DG#3 Inoperability

A-5Attachment143797, Corrective Action Extension156020, Unit 2 Reactor Scram

156039, 2-DG3-HLCR Relay Coil Failure

158668, Loss of Emergency Bus E1

159208, Rework 2-DG2-PS-6521-2 Found Out of Calibration

161419, Latent Organizational Weakness

164345, Unplanned LCO Entry Due to DG Fuel Oil Day Tank Particulate

165123, DG3 Collector Ring Arc Brush Inspection

165765, EDG Excitation Transformer Overloading Condition

166409, Comprehensive Assessment of DG System Health

167548, DG4 ASCR Relays

167802, 2-DG4-SHTDN-INTLK-Valve Continuously Venting Air

175111, Modification Changes Not Captured in EDB

188327, Rework of DG1 Reverse Power Annunciator

21485, Transient Condensate System Flow Exceed OGP-13

115446, RCIC Oil Strainer Differential Pressure Alarm

155773, 2-E41-F001 did not Cycle Closed During PT-9.2

153694, Replacement of 2-E51-PS-5536 RCIC Oil Pressure Switch

155447, MCC 2XDA Compartment Overheating

159141, Unit 2 HPCI Steam Line Vibration

2901, Unplanned LCO Entry - LCO 3.6.1.3

176780, RCIC Oil Pressure Alarm

183102, 1-E41-F079 Failure and HPCI Inoperability

183188, Work Order

769982-01 Lost

187282, Maintenance Rule Tasks Performed without Being Qualified

189270, U1 RCIC Vacuum Breaker Check Valve Not Opening as Required

191204, Unclear Procedures Result in Unnecessary Loss of Generation

198380, RCIC Keepfill Failure

200312, 0AI-58.2 Procedure Needs Enhancements

203629,

OPT-20.10 HPCI Vacuum Breaker Check Valve Failure

203756, Defective Test Medium During OPT-20.10

207570, Alternate Source Term - ESF Leakage

209081, GE

SIL 375 (ECCS Keepfill) Disposition

209265, Water Found in HPCI Exhaust Diaphragm Switches

209284, Unplanned LCO Entry - Unit 2 HPCI Inoperability

211380, HPCI Main Pump Outboard Seal Leak

211494, Inconsistent Implementation of ACP Vehicle Search

211516, HPCI Room Temperature Exceeded 104 degrees during LOOP Event

218728, Unit 2 RCIC Vibration DataMaintenance Work Orders/Work Requests741438, 1-UPS-LTG/COMM-NVT, Lost Power Momentarily675359, 1-UPS-LTG/COMM-NVT Swapping to Alternate Source

968132, 1-UPS-LTG/COMM-NVT Swapped to Hard Source

28882, 2-UPS-2A, Recorder Installation

831617, 2-UPS-2A, Check the MIC and Sensing Boards

20491, 2-UPS-2A, 2B & 2-UPS-LTG/COMM Inspection

A-6Attachment775843, 0PM-BKR008 on 2-2CA-C07-52, Primary UPS Unit 2A765413, 2-UPS-2A, Perform Visual Inspection

666349, 2-UPS-2A, Perform Visual Inspection

644124, 2-UPS-2A, Perform Visual Inspection

574874, 2-UPS-2A, Perform Visual Inspection

731017, 2-UPS-2A, Perform Visual Inspection

699241, 2-UPS-2A, Perform Visual Inspection

23504, 2-UPS-2A, 2A Primary UPS Cooling Fan

744757, 2-UPS-2A, Failure of Normal Source

2405, 2-UPS-2A, Replace Capacitors

406325, 2-UPS-2A, Component Replacement

574796, 1A & 1B UPS, Perform Visual Inspection

574797, 1A & 1B UPS, Perform Visual Inspection

659639, 1-UPS-LTG/COMM-NVT Replace Capacitors C113A - D

580501, Checkout UPS Inverters IAW Instructions

659637, 2-UPS-LTG/COMM-NVT Replace Capacitors C113A - D

644104, 1A & 1B UPS, Perform Visual Inspection

684850, 2-UPS-LTG/COMM-NVT Replace Circuit Cards

650732, 1A & 1B UPS, Perform Visual Inspection

2967, 1A & 1B UPS, Perform Visual Inspection

718213, 1A & 1B UPS, Perform Visual Inspection

24962, Checkout UPS Inverters IAW Instructions

2469, 1A & 1B UPS, Perform Visual Inspection

734630, 2-UPS-LTG/COMM-NVT Indicating Light Dim

2294, 1-E11-F006B-MO, Found Grease in Need of Replacement

405234, 2-E11-F04A-MO, Replace EQ Components

233149, 1-SW-V382, Remove Temp Mod Installed

739214, 1-E11-PCV-F100, PCV Norm Regulates

709804, 2-SW-FS-114, 2C CWIP Tripped

697120, 1-SW-PS-3214, 1B NSW Pump Auto Start

2515, 2-E11-PI-R002B, 2B RHR Running Suction Pressure

633893, 2-SW-2A-CONV-PMP-M, 2A CSW Upper Bearing Temp

806218, 1-E11-FI-K603A, Is Reading Approx 750 gpm

798708, 2-SW-V118, Failed to Stroke

844555, 2-SW-PI-1157-1, RHRSW Pump Reads Low

20397, 2-SW-PSL-1178,

CS 'B' SW Vital Header Low

24053, 2-E11-F048B-MO, Will Not Engage Manually

28422, RHR Pump 1D Seal Cooler Low Flow

606042, UT 5 Areas of SW Piping

561928, 2-E11-F004D-MO, Found Bad Grease

24053, 2-E11-F048B-MO, Will Not Engage Manually

2398, 1-SW-V20, Indicates Dual Position

561945, 2-SW-2B-CONV-PMP-M, Motor Stator Temp

901093, 2-SW-PI-1157-1 Reads Low, RHR SWP

975838, 2-E11-FR-R608 Indicates 7500 Gpm when pumps shutdown

976419, 2-SW-FT-5115, Oscillating Flow Condition

893993, 1-E11-C002C-HX, 1C RHR Seal Cooler

A-7Attachment472953, 2-E51-IV-1611 Valve and Piping Need Replacement due to Corrosion506831, 2-E51-PS-5536 Pressure High During RCIC Operation

970871, 1-E41-PSH-N012A-D Check for Water in Sensing LinesSelf- Assessments140125, 8/15/05, Assessment of the Adequacy of Barriers to Prevent Unplanned Exposures177821, 6/15/06, Chemical Control

177826, 11/10/06, Closed Cooling Systems Water Chemistry Controls

177829, 9/22/06, E&RC Self Evaluation Program

145004, 7/14/05, 2005 BNP Environmental Risk Assessment

B-EC-05-01, 7/19/05, NAS Environmental and Chemistry Assessment

13397, 9/23/04, Radioactive Material Control

B-RP-06-01, 2/22/06, NAS Radiation Protection

B-RP-05-01, 2/23/06, NAS Radiation Protection

140541, 9/29/05, Cooling Water Reliability (

GL 89-13) Program

14072, Corrective Action Program with Integration of the Operating Experience ProgramOther DocumentsSD-52, 120 VAC Electrical System, Rev.

2140543, System Monitoring & Trending Self-Assessment

B-ES-06-01, BNP Engineering Functional Area Assessment

B-SP-05-01, BNP Equipment Reliability Assessment

BNP Engineering Monthly KPI Report, December 2006

th

QTR 2006 Self-Evaluation Roll-Up & Trend AnalysisDecember 2006 Operating Experience Health Data January 2007 Operating Experience Coordinator Teleconference Agenda

BNP Operating Experience Program Handout November 2006 System Health Summary Report Brunswick Plant Quarterly CAP Rollup and Trend Analysis (2005-2006)