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:	Randy Musser NRC/RGN-II/DRP/RPB4
To:	Scarola J Carolina Power & Light Co
References
IR-07-007
Download: ML070820476 (30)

Text

rch 23, 2007

SUBJECT:

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

Dear Mr. Scarola:

On February 23, 2007, the US Nuclear Regulatory Commission (NRC) completed a team inspection 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 to the identification and resolution of problems, and compliance with the Commissions 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, problems were 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 significance determination 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 NRCs 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&L 2 Director, 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 NRCs Rules of Practice, a copy of this letter and its enclosure will be 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/

Randall A. Musser, Chief Reactor Projects Branch 4 Division of Reactor Projects Docket Nos.: 50-325, 50-324 License Nos: DPR-71, DPR-62

Enclosure:

Inspection Report 05000325, 324/2007007 w/Attachment: Supplemental Information

REGION II==

Docket 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 SE Southport, NC 28461 Dates: 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 Safety Approved by: Randall A. Musser, Chief Reactor Projects Branch 4 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

IR 05000325/2007007, 05000324/2007007; 02/05-09/2007, 02/19-23/2007; Brunswick Steam

Electric 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 untimely completion of corrective actions.

The inspection was conducted by a Senior Resident Inspector, two Resident Inspectors, and a Senior 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 Problems The team concluded that in general, problems were adequately identified and evaluated, and effective 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, several examples 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 licensees 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.

Cornerstone: Mitigating Systems

Green.

A self-revealing, non-cited violation of 10CFR50, Appendix B, Criteria XVI, 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 licensee failed to implement timely preventive maintenance to inspect the condition 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 equipment performance 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)).

Licensee Identified Violations

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

REPORT DETAILS

4OA2 Identification and Resolution of Problems

a.

Assessment of the Corrective Action Program

(1) Inspection Scope The inspectors reviewed items selected across the seven NRC cornerstones of safety to determine 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 licensees 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 licensees 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/DC power, 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 verify 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 to verify 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 NRCs assessment of the licensees CAP.

Documents reviewed are listed in the Attachment.

(2) Assessment Identification of Issues. The team determined that the licensee was effective at identifying 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, the team 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 were adequately prioritized and entered into the CAP consistent with the licensees 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 licensees CAP Coordinator indicated that management was focusing greater attention in this area, as well as reducing the backlog of old open CAP items. Based on the high number of extensions observed by the team for 2006 generated NCRs, this area remained an area for improvement.

In general, the licensees evaluation of issues in the CAP were considered to be effective. 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 Lighting and 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 its intended function.

A total of four significant adverse condition, root cause evaluations were completed 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 power source revealing a faulty B phase driver card. Based on the teams comments, 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 Following Stroke 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 discussed in Section 4OA7 of this report.

In addition to the above mentioned more significant evaluation weaknesses, the team identified 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 and Environmentally 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 fans 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 evaluation identified 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 Diaphragm Switches: While it was considered that condensation from room temperature differences between the Residual Heat Removal and HPCI was the source of the moisture 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 teams identification of this documentation inconsistency.

• NCR 115446, RCIC Lube Oil Strainer High Differential Pressure: The team noted 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 the fact 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 licensees 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-Assessment 140541: 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 licensees 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, an air 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 licensees 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 licensees earlier evaluation. The licensee initiated 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 and implemented 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 a separated 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 Series relays 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 untimely implementation 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 equipment issue 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 written to 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 underground piping integrity program. Subsequently, PM routing documents to perform 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 term corrective 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 Failure of 2C Conventional Service Water Pump Due to Pump Shaft Coupling Corrosion

Introduction.

A Green self-revealing non-cited violation (NCV) of 10 CFR 50, Appendix B, 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 a configuration 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 these inspections did not occur on submerged SW pump components prior to the 2C CSW pump failure on July 26, 2006.

In July 2002, NCR 64786 was written to address a continued issue with SW pump shaft pitting 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 header pressure. 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 licensees root cause evaluation associated with the 1996 and 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 prevent various types of corrosive attacks left the developing defects unnoticed until failure occurred.

Analysis.

The performance issue associated with this finding is that the licensee failed to take 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 coupling was 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. A phase 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 licensees 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 Emergency Diesel Generator Allen Bradley 700DC Series Relay Failures The inspectors noted weaknesses associated with the licensees evaluations and untimely 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 contributed to additional unavailability time for repair. The following is a time line of the identified relay issues and assessment of the licensees 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 November 11, 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 corrective action 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 Allen Bradley 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.

A critical relay was defined as one that would cause the EDG to be inoperable if it 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 comprehensive assessment 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 #2 tripped 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 Series Relay failures identified over the past four years and the licensees 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 licensees 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 Scope The inspectors examined licensee programs for reviewing industry operating experience, reviewed the licensees 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 communications, 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) Assessment The team determined that the licensee was effective in screening operating experience for 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) Findings No findings of significance were identified.

c.

Assessment of Self-Assessments and Audits

(1) Inspection Scope The 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 NRCs CAP assessment results against the licensees assessment of the CAP effectiveness.

(2) Assessment The 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.

(3) Findings No findings of significance were identified.

d.

Assessment of Safety-Conscious Work Environment

(1) Inspection Scope During the reviews of selected NCRs, the inspectors conducted interviews with members 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 NCRs and 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) Assessment The team concluded that licensee management emphasized the need for all employees to 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) Findings No findings of significance were identified.

4OA6 Meetings, Including Exit

Exit Meeting Summary

On February 23, 2007, the inspectors presented the inspection results to Mr. B. Waldrep and other members of his staff. The inspectors confirmed that proprietary information was not retained following the inspection.

4OA7 Licensee Identified Violations

The following violation of very low safety significance (Green) was identified by the licensee and is a violation of NRC requirements which met the criteria of Section VI of the 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 licensees 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. ONeill, 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 II

Gene DiPaolo, Senior Resident Inspector

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

05000325, 324/2007007-02 URI Repetitive Failures of EDG Allen Bradley 700DC Series Relays (Section 4OA2.a.(3)(ii))

Opened and Closed

05000324/2007007-01 NCV Failure to Adequately Evaluate and Correct Condition Adverse to Quality Resulting in 2C CSW Pump Failure (Section 4OA2.a.(3)(i))

Closed

None.

Discussed

None.