IR 05000456/2005012
| ML053430126 | |
| Person / Time | |
|---|---|
| Site: | Braidwood  |
| Issue date: | 12/09/2005 |
| From: | Richard Skokowski NRC/RGN-III/DRP/RPB3 |
| To: | Crane C Exelon Generation Co, Exelon Nuclear |
| References | |
| IR-05-012 | |
| Download: ML053430126 (29) | |
Text
December 9, 2005
SUBJECT:
BRAIDWOOD STATION, UNITS 1 AND 2 NRC PROBLEM IDENTIFICATION AND RESOLUTION INSPECTION REPORT 05000456/2005012(DRP); 05000457/2005012(DRP)
Dear Mr. Crane:
On October 28, 2005, the U.S. Nuclear Regulatory Commission (NRC) completed a team inspection at the Braidwood Station, Units 1 and 2. The enclosed report documents the inspection findings which were discussed on October 28, 2005, with Mr. K. Polson and other members of your staff.
This inspection was an examination of activities conducted under your license as they relate to identification and resolution of problems, and compliance with the Commissions rules and regulations and with the conditions of your operating license. Within these areas, the inspection involved selected examination of procedures and representative records, observations of activities, and interviews with personnel.
On the basis of the samples selected for review, there were no findings of significance identified during this inspection. The team concluded that problems were properly identified, evaluated and resolved within the problem identification and resolution (PI&R) programs. However, the team identified a few examples where the implementation of the corrective action program lacked the rigor needed to ensure the effectiveness of the program. Specifically, the team identified instances where extent of conditions evaluations of identified problems were narrowly focused and a circumstance where technical rigor for a potentially safety significant issue was not up to the station management expectations. The team also identified an example where your staffs response to previous NRC non-cited violation may have not been thorough or complete.
In accordance with 10 CFR 2.790 of the NRCs Rules of Practice, a copy of this letter and its enclosure and your response to this letter 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/
Richard A. Skokowski, Chief Branch 3 Division of Reactor Projects Docket Nos. 50-456; 50-457 License Nos. NPF-72; NPF-77
Enclosure:
Inspection Report 05000456/2005012(DRP); 05000457/2005012(DRP)
w/Attachment: Supplemental Information
REGION III==
Docket Nos:
50-456; 50-457 License Nos:
05000456/2005012(DRP); 05000457/2005012(DRP)
Licensee:
Exelon Generation Company, LLC Facility:
Braidwood Station, Units 1 and 2 Location:
35100 S. Route 53 Suite 84 Braceville, IL 60407-9617 Dates:
October 11 through October 28, 2005 Inspectors:
B. Dickson, Senior Resident Inspector, Clinton G. Roach, Resident Inspector A. Klett, Reactor Inspector, RIII Approved by:
R. Skokowski, Chief Branch 3 Division of Reactor Projects
Enclosure
SUMMARY OF FINDINGS
IR 05000456/2005012(DRP), 05000457/2005012(DRP); 10/11/2005 - 10/24/2005; Braidwood
Station, Units 1 and 2. Identification and Resolution of Problems.
The inspection was conducted by a senior resident inspector, a resident inspector, and a Region III reactor inspector. There were no findings identified during this inspection. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 3, dated July 2000.
Identification and Resolution of Problems Overall, the team concluded that problems were being adequately identified, evaluated, and corrected. Issues captured in the corrective action program were appropriately screened and evaluated for root or apparent causes and workers generally expressed positive views about the program. However, the team identified a few examples where the implementation of the corrective action program lacked the rigor needed to ensure the effectiveness of the program.
Specifically, during the review of some root cause reports the team identified that the scopes for extent of condition were narrowly focused. The team also identified a circumstance where the technical rigor related to a technical-specification required evaluation did not meet the station management expectations. The Nuclear Oversight organization was considered thorough and challenged corrective action program performance based on the numerous examples of assessment findings reviewed during the inspection. The team also observed that in most cases, the station had reasonably addressed previously identified NRC issues.
REPORT DETAILS
OTHER ACTIVITIES (OA)
4OA2 Problem Identification and Resolution
This inspection counts as one inspection sample.
.1 Effectiveness of Problem Identification
a. Inspection Scope
The team assessed the licensees processes for identifying and correcting problems.
The team reviewed selected plant procedures and program description manuals, interviewed plant and contractor personnel, and attended various station meetings to understand the stations processes for initiating the corrective action program (CAP)and related activities.
The team reviewed previous NRC-identified issues, operating experience reports, Nuclear Oversight (NOS) reports and trend assessments to determine if problems were being identified at the appropriate threshold and entered into the CAP. The team also reviewed issue reports to determine if the significance levels of the issues were appropriately assigned. The team reviewed selected operator logs generated since January 2005 for both Braidwood Units 1 and 2 to determine whether identified issues were being captured in the CAP.
Although the review covered the last 5 years, the team focused on items generated since the 2003 NRC Problem Identification and Resolution Inspection (PI&R) (Inspection Report 05000456/2003009(DRP); 05000457/2003009(DRP)) for a more in-depth review.
The team performed an in-depth review of the emergency diesel generators (EDGs),instrument air systems and auxiliary feedwater systems to evaluate the licensees processes for equipment monitoring, maintenance rule implementation, and to identify if issues were being appropriately addressed. These systems were considered of high risk significance. The team interviewed system managers, reviewed cause and operability evaluations, system health reports and system monitoring program results, and performed partial system walkdowns. In particular, the team searched for material condition items or issues, component reliability and longstanding design issues which looked like potential trends and assessed whether the licensee had appropriately identified and captured these trends within the CAP. In addition to the three systems described above, the team also reviewed issue reports generated since January 1, 2004, for the boric acid corrosion/leakage control program for potential trends.
The team reviewed selected audits and self-assessments of the corrective actions, operations, maintenance, engineering and plant support (radiation protection, chemistry, and emergency preparedness) programs. The team evaluated whether these audits were being effectively managed, adequately covered the subject areas and whether identified issues were properly captured in the CAP. In addition to the document review, the team also interviewed licensee staff regarding the implementation of the audit and self-assessment programs.
The specific documents reviewed are listed in the Attachment to this report.
b. Observations and Findings
The licensee operated a broad, low-threshold CAP governed by corporate-level policies and procedures. A shared computerized database was used for creating individual reports and for subsequent management of the processes of issue evaluation and response. This included determining the issues significance, addressing such matters as regulatory compliance and reporting, and assigning any actions deemed necessary or appropriate. Through interviews, the team determined that individuals were encouraged to initiate an issue report for any item they personally felt needed attention or action. Very large numbers of issues were entered into the computer database for the CAP since the last problem identification and resolution inspection. The team noted that the majority of these issue reports were of very low individual significance.
Although the team concluded that problems were being adequately identified, there were some vulnerabilities noted involving the following: 1) level of participation in the program by specific working groups and 2) the level of feedback availability following closeout/resolution of an identified issue. These matters are discussed in greater detail below.
b.1 Observations on Thresholds for Entering Known Problems into the Corrective Action Program In general, station personnel effectively identified issues at a low threshold and entered problems as issue reports into the corrective action program. As noted, all individuals were encouraged to initiate an issue report for any issue they felt needed attention. The licensee also encouraged the staff to use issue reports to report suggested enhancements to station activities or equipment. The general nature of the CAP administrative procedures necessarily left some room for interpretation regarding the threshold for documenting an issue; however, most individuals stated that there was generally no issue too insignificant to put into the CAP. Upon entry into the CAP, each issue report received a significance level classification (Level 1 through 5).
Still, the team observed a considerable variation in the level of direct participation in the program. For example, in the mechanical maintenance department, working-level individuals relied on their supervisors for entering issues into the CAP. Several individuals in that department stated they did not know how to use or did not feel comfortable using the shared computerized database to generate issue reports.
b.2 Observations on Availability of Feedback Following Issue Closeout or Resolution Several individuals interviewed by the team stated no direct feedback was given to the individuals if they indicated via the shared computerized database that they disagreed with the disposition/resolution of an issue report. Additionally, some employees that originated issue reports expressed frustration with being assigned to resolve the issues when additional assistance was desired. The team however, noted that this frustration did not appear to affect the effectiveness of the resolution for the issues identified.
b.3 General Corrective Action Program Implementation Observations The licensees program had integral processes for identifying or recognizing conditions adverse to quality. As noted, the program authorized and encouraged all staff to initiate issue reports as appropriate. Once initiated, issue reports were first reviewed by the Department Corrective Action Program Coordinators for completeness and for assignment of the applicable trend coding. The issue reports were then reviewed by the Station Ownership Committee to assign priority and actions. The licensee informed the team that the Corrective Action Program Coordinators responsibilities included prompt routing of issues that had potential bearing on plant equipment operating conditions or otherwise had the potential to affect plant operations to the operating shift for review by the Shift Manager.
The team noted that newly generated issue reports were reviewed on a daily basis by the Station Ownership Committee in accordance with LS-AA-120 Issue Identification and Screening Process. However, during the review of LS-AA-120 the team noted that there was no guidance regarding the minimal qualifications (knowledge and experience)required for a Station Ownership Committee member. The team questioned the licensee regarding whether there had been minimal qualifications established by the licensees program for the Station Ownership Committee members. The licensee referred the inspectors to Step 2.16 Screening Committee Knowledge Based of procedure WC-AA-106 Work Screening and Processing.
Following the review of the WC-AA-106, the team questioned whether the licensee was fully meeting the intent of Step 2.16. For example, the team noted that a Station Ownership Committee member representing radiation protection department was a recent college graduate had approximately 6 months of plant experience according to the licensee. However, Step 2.16, specifies that the radiation protection representative must be knowledgeable of radiation control classification, engineering controls, and/or special instructions that will impact radiation workers. The team was concerned with whether an individual of this experience level would possess these core competencies to be an effective screening team member. Based on this concern, the team attended several Station Ownership Committee and Management Review Committee meetings and observed that issues were indeed being appropriately challenged.
During the teams review of operating logs they noted that issues identified in the operator logs were appropriately documented in issue reports, and potential operability concerns were generally routed to operations shift management for review. The team also reviewed several issue reports that were assigned a significance level of 4 (minor)to determine if they were appropriately classified as such. No issues were identified The team reviewed Operating Experience (OPEX) information and reports and discussed OPEX program activities with the OPEX coordinator. The team observed that industry experience was appropriately captured in the corrective action program. The team reviewed issue reports containing industry operating experience to determine if applicability to Braidwood was reviewed by licensee personnel. The team also determined that licensee personnel were reviewing Part 21 reports that were applicable to Braidwood and appropriately addressing the issues contained in those reports.
b.4 Selected System and Program Reviews The team performed partial walkdowns of the 1A and 1B emergency diesels generator, the instrument air system, and Units 1 and 2 motor-driven and diesel-driven auxiliary feedwater system. In general, the team noted that equipment and program deficiencies had been entered into the corrective action program and selected operating experience reports were properly evaluated and dispositioned by the system engineer/ program manager. However, the team observed that there were relatively long standing issue reports and equipment status tags for oil leaks on both the emergency diesel generators and auxiliary feedwater systems. These issues were being tracked by the licensee individually, and none of them presented an operability concern. Based on the sample of issue reports reviewed, the team also concluded that issues affecting equipment availability were appropriately evaluated for maintenance rule applicability.
Issues associated with the radiation protection, emergency preparedness, and fire protection programs at Braidwood were reviewed for successful problem identification and resolution. The inspectors reviewed issue reports; routine audits; site and corporate procedures; and apparent, root and common cause evaluations. In general, issues were identified, dispositioned, and corrected in a timely and effective manner. The team identified one area in the fire protection program where corrective actions have not been effective to prevent recurrence. Specifically, multiple issue reports had been written during the inspection period (00273639 and 00312986) regarding smoking in unauthorized areas of the plant, including the area around the hydrogen tank farm. The inspectors performed a walk down of the hydrogen tank farm and noted evidence of unauthorized smoking which resulted in the generation of Issue Report 00391078. The licensee noted additional areas of unauthorized smoking on power block building roof tops as a part of its extent of condition plant walk down. Although the inspectors considered the licensees corrective actions to be ineffective to prevent recurrence, this issue was not considered a significance condition adverse to quality and therefore it was not a violation of NRC requirements.
b.5 Nuclear Oversight Overall, NOS conducted well-planned, thorough audits. They identified numerous findings and observations across the spectrum of performance, including issues of both proper and improper corrective action program implementation. In general, the NOS assessments were thorough and appropriately critical of the areas being evaluated. In particular, the team noted that the April 18, 2005, NOS assessment of the corrective action program was broader in scope and more critical than the licensees subsequent, April 25, 2005, corrective action program self-assessment.
NOS worked primarily under well-defined and focused audit and surveillance procedures, which produced structured reports of results in the defined areas examined.
However, these reports contained relatively few examples of NOS making broader judgements about the meaning of the issues they identified, or of their potential generic implications, their common causes, or their assessment of broad organizational weaknesses. Instead, activities and reports reflected a focus on process details. In this regard, several of the licensee personnel interviewed by the team characterized the NOS approach as too detail oriented. The team viewed this as a potential missed opportunity for the NOS group to contribute expertise to the broadest and most in-depth understanding of the issues and discussed this concern with NOS staff.
.2 Review and Evaluation of Issues
a. Inspection Scope
The team reviewed selected root cause evaluations and common cause analyses (CCAs). Attributes reviewed included the adequacy of the extent of condition reviews, including evaluations of potential common cause or generic concerns and, as applicable, the adequacy of associated operability and reportability determinations. The team reviewed the various controlling procedures and selected records of activities, visually inspected the selected systems, interviewed cognizant station personnel and observed various licensee meetings. The specific documents reviewed are listed in the to this report.
b. Observations and Findings
b.1 Evaluations The team reviewed several CCAs that were performed in response to trends identified within the CAP. For the most part the team concluded that the CCAs appeared to have been completed in accordance with the licensees trending and coding manual. The team also reviewed root cause evaluations. In general, the licensees evaluations were found to be broadly-based, technically sound, and focused on safety. However, the team identified a few shortcomings with the extent of condition reviews associated with root cause evaluations and the technical rigor associated with a technical specification required common mode failure evaluation. Specific examples are provided below. No violations of NRC requirements were identified.
Root Cause Report Regarding the Precipitation of Calcium Carbonate at Braidwood Ultimate Heat Sink The team reviewed the root cause evaluation that was performed for Issue Report 00199206, Lake Chemistry Trend - Calcium Carbonate Issue. In February 2004, calcium carbonate precipitated out of the lake that served as a source of water for the Circulating Water (CW), Essential Service Water (SX),
Non-Essential Service Water (WS) and the Fire Protection (FP) systems. The Calcium Carbonate (CaCO3), affected several components within the above systems, such as valve seating surfaces on several CW components, cubicle and pump gear oil coolers, piping, strainers, and the jockey fire pump. Several components were disassembled and cleaned as corrective actions. The team reviewed the licensees extent of condition review section of the root cause evaluation and noted the following shortcomings with the extent of review. Specifically the licensee did not address the possibility for the CaCO3 to have affected other portions of the fire protection system, in particular the piping and sprinklers downstream of the jockey pump. The team was concerned that if the sprinklers opened, CaCO3 could break loose in the piping and plug some of the sprinklers or form obstructions at the fittings. In addition, the team noted that the extent of condition report did not address all of the valves located in the SX system, and they were concerned that CaCO3 buildup could adversely affect the ability of the valves to function when required.
The inspectors noted that several issue reports that were written after the precipitation event that documenting problems with SX valves (i.e., valves were difficult to operate, corrosion was found in the valve seating area, valve stems were bent or twisted, valves did not stroke smoothly during calibration, and valves were failing to fully open and close). The inspectors also noted several condition reports were written after the precipitation event that documented problems with FP sprinklers (i.e., sprinkler heads were blocked, corroded, covered with mineral deposits, leaking, and flow switches were fouled with sediment). The inspectors raised concerns regarding the root cause evaluation not addressing the possibility that CaCO3 was contributing to these issues.
In response to the teams concerns, the licensee provided a May 2005 Action Request, (AR) 00336783, NOS IDd Lake Precip Eval Enhancement for Vlvs/Instr Tubing, that documented NOSs concerns about the effects of CaCO3 deposits in valves and small bore (instrument) tubing. The AR stated that the corrective actions from the lake precipitation event root cause evaluation and related focused area self assessment did not document the issue of CaCO3 deposits on valves and instrument tubing as being properly addressed. The extent of condition for this AR stated that the CaCO3 issue also applied to the CW/WS/FP systems and recommended that the CS/WS/FP system managers review this AR for applicability and initiate additional actions or new issue reports if any deficient conditions were identified. Responses to this AR from SX and FP personnel stated that, subsequent to the precipitation event, preventive maintenance and surveillance tests performed on these systems showed no CaCO3 build-up.
Although the team considered the licensees final corrective actions for the CaCO3 issue to be acceptable, and no violations of NRC requirements were identified, the team noted shortcomings in the original root cause evaluation extent of condition review.
Specifically, the root cause evaluation did not thoroughly address the possible effects of CaCO3 build-up in the internal FP piping and downstream sprinklers and fittings. In response to the teams observations, the licensee initiated Issue Report 00390590, EOC Review Weak For Calcium Carbonate in FP System, to perform a thorough extent of condition review for the effects of CaCO3 in the FP system and to update the root cause evaluation to reflect the revised EOC and any actions that need to be taken.
Common Mode Failure Evaluation for Emergency Diesel Generator On October 12, 2005, while the team was onsite, the 2A Emergency Diesel Generator failed a surveillance test. Specifically, the 2A EDG failed to reach rated frequency and voltage within 10 seconds of starting (Issue Report 385062) as required by the licensees Technical Specifications. As a result of this failure, the technical specification required that the licensee to test the other division EDG or perform a common mode failure analysis to ensure that the other division EDG would not experience the same problem.
In response to the failure the licensee completed the common mode failure analysis in leu of testing the other division EDG. The team reviewed the common mode failure analysis and concluded that it lacked the technical rigor to justify not testing the other division EDG. Specifically, the common mode failure analysis document, which was accepted by the Shift Manager as demonstrating operability of the 2B EDG, did not identify a specific failed component in the 2A EDG and licensee justified 2B EDG operability based on the fact that all of its components were within their normal maintenance periodicity and that the diesel had passed all previous surveillance tests.
The team noted that these were the conditions that existed on the 2A EDG just prior to its failed surveillance run. The team along with the NRC resident office addressed these issues with licensee management. Subsequently the licensee tested the 2B EDG and proved that a common failure condition did not exist. Since all actions were completed within the Technical Specification-required times, no violations of NRC requirements occurred.
b.2 Trending The licensee regularly performed analyses of issue reports for adverse trends. The inspection team reviewed a number of issue reports generated by the licensee relating to potential or actual adverse trends. The team did not identify any trends that were not already identified by the licensee. The team noted that when actual declining trends were identified, the licensee performed Common Cause Analysis to understand the adverse trend and to determine appropriate corrective actions. During the last Problem Identification and Resolution Inspection, the NRC identified that, between February and November 2002, six failures and one out-of-tolerance for the same model pressure switch used on the diesel generators occurred. As each switch failed, it was replaced with a switch of a new model because the old one was obsolete. At that time the team did not have an operability concern because trips initiated by the pressure switches were automatically overridden during an emergency start. However, the team noted that the licensee had not identified the multiple failures of the same model switch as an adverse trend. The team also noted that the corporate procedure ER-AA-520, Instrument Performance Trending, Revision 3, required that instruments found out-of-tolerance be trended, but did not require failed instruments to be trended.
During this inspection, the team confirmed that since the last inspection the licensee had identified multiple failures on the same/similar components and generated a number of engineering evaluations to determine the cause of the failures. The team also concluded that the licensee had since then generated issue reports documenting these repetitive failures in accordance with ER-AA-520. The team was concern however, that these issue reports were not readily retrievable by the licensee corrective action program staff, due to inconsistent use of trending codes during the initial issue review.
b.3 Focused Area Self-Assessments The team reviewed selected FASA reports and concluded the process was being effectively implemented and that the results were valuable in directing corrective action resources efficiently and effectively.
.3 Effectiveness of Corrective Action
a. Inspection Scope
The team reviewed selected condition reports and associated corrective actions to evaluate the effectiveness of corrective actions and to determine whether corrective actions were being identified and implemented in a timely manner, commensurate with the safety significance of the issues. The team also assessed licensee corrective actions stemming from previous Non-Cited Violations. A listing of the specific documents reviewed is in the Attachment to this report.
b. Observations and Findings
The team concluded that, in general, corrective actions were adequately implemented and tracked to completion, corrective actions appeared effective in addressing the parent issue, and corrective action timeliness appeared to be commensurate with the safety significance of the issues. During the teams reviewed of the licensees corrective actions associated with a previous non-cited violation the following unresolved item was identified:
Introduction:
The inspectors identified an Unresolved Item (URI) associated with the corrective actions taken in response to a Non-Cited Violation (NCV 50-456/457/03-05-02) from the 2003 Triennial Fire Protection Baseline Inspection performed at Braidwood.
Description:
NRC Inspection Report 2000-06 documents a Non-Cited Violation (NCV 50-456/00-06-06(DRS); 50-457/00-06-06(DRS)) from a Triennial Fire Protection Baseline Inspection performed at Braidwood in 2000. The NCV was issued for the licensees failure to provide objective evidence that the molded case circuit breakers at the 120Vac and 125Vdc voltage levels had been periodically manually exercised, inspected, and tested as required by the Braidwood Stations Fire Protection Report, Chapter 2.4, Safe Shutdown
Analysis.
The licensees corrective action for this NCV was the establishment of a program to test and manually exercise molded case circuit breakers (MCCB).
The licensees MCCB testing program was established in 2002. The program specified testing safety-related MCCBs over a 6-year period and non-safety related MCCBs over a 12-year period. During the licensees testing, numerous Westinghouse HFB magnetic-only MCCBs were tripping out of tolerance (OOT) high. On average the breakers were tripping approximately 20 percent OOT high on all three phases.
Condition Report 00105657 was initiated to document, evaluate, and address the adverse trend and a potential common mode failure associated with the instantaneous trip settings on these breakers. In response to these failures, the licensee would replace any originally installed breakers with breakers from another manufacturer. In addition, the licensee evaluated each OOT condition to verify that the breaker would have interrupted the minimum fault current and that coordination requirements were met.
In the 2002 time-frame, the licensee sent some of the breakers that failed OOT high to Exelon Power Labs. The lab concluded that the breakers were OOT high due to distortion or twisting of the breaker trip bars, which caused the trip setpoints to drift (Reports BRW-06222 and BRW-21082). The licensee contacted the breaker manufacturer, Westinghouse, to investigate further. Westinghouse concluded that the breakers were tripping high due to hardening of the internal lubrication of the breaker and they recommended cycling/testing the breakers on a yearly basis. Nonetheless, the licensee did not increase the testing frequency of these breakers as recommended by the vendor.
NRC Inspection Report 50-456/45703-05 documented a Non-Cited Violation (NCV 50-456/457/03-05-02) from the following Triennial Fire Protection Baseline Inspection. The NCV of 10 CFR 50, Appendix B, Criterion XVI was issued for the licensees failure to establish a program and to manually cycle/exercise MCCBs at the 120Vac, 125Vdc, and 480Vac voltage levels on a preestablished periodic basis to ensure proper breaker operation as recommended by the breaker vendor, by the NEMA AB-4 standard, and as required by Braidwoods Safe Shutdown
Analysis.
During this PI&R inspection, the inspectors chose to review the 2003 NCV to determine if the licensees corrective actions in response to the NCV were adequate and timely.
The licensee informed the inspectors that in 2004 a sample of nine breakers that tested OOT high was sent to an independent laboratory, Wyle Laboratories, to investigate the cause of the OOTs. Wyle Report No. 10514R04, Failure Analysis of Westinghouse HFB Breakers From Exelons Braidwood Station, concluded that while the data was not completely consistent, it appeared that the cause of the failures was something other than lubrication. The Wyle tests indicated that the problem may have been caused by the magnetic properties of the trip flaps and that the MCCBs may have been tripping high since the initial manufacture of the breakers. The licensee took no additional corrective actions as a result of this information.
Westinghouse issued a technical bulletin, TB-04-13, Replacement Solutions for Obsolete Classic Molded Case Circuit Breakers, UL Testing Issues, Breaker Design Life and Trip Band Adjustment, dated June 28, 2004. TB-04-13 recommended that breakers be cycled each year (or at least each refueling outage) for 6 to 12 times at no load conditions, to keep lubrication well distributed on moving parts. A periodic functional test to NEMA AB4 guidelines, on a representative sample, was also recommended. In addition, Westinghouse defined the design life of these breakers to be 20 years. No additional corrective actions were taken as a result of this information.
Based on the causes described in the Power Labs and Wyle Laboratories reports, the team questioned the licensee regarding potential generic manufacturing implications associated with these failures. In response to the teams questions, the licensee provided Assignment 6 from AR 00105657 dated November 1, 2002. This assignment was to determine if the breaker issue required a response pertaining to 10 CFR Part 21, Reporting of Defects and Noncompliance. The assignment was deferred to June 2003 pending results of an analysis from Westinghouse. Upon receipt of the Westinghouse analysis the assignment was closed with no further actions required. The licensee did not issue a Part 21 report nor provide a documented justification for why a report was not warranted. Therefore, as a result of the teams question, the licensee initiated Issue Report 00396317 on November 8, 2005 to document the inadequate closure of assignment.
Based on the relatively large rate (~ 20 percent) of high OOT results during breaker testing coupled with a large population of the applicable MCCBs that have not been tested since the plants construction, the team considered the adequacy of the licensees corrective actions to address this concern to be unresolved. Specifically, the team needed additional information to determine:
!
the potential OOT high conditions would not adversely impact the worst-case coordination studies;
!
the acceptability of not increasing the cycling and testing of these breakers as recommended by the vendor; and
!
the generic manufacturing implications of the failure mechanism.
This issue is considered an unresolved item (URI) (URI 05000456/2005012-01; 05000457/2005012-01).
.4 Assessment of Safety-Conscious Work Environment
a. Inspection Scope
The team interviewed approximately 25 members of the plant staff, across all major work groups and all levels of responsibility. The purpose of the interviews was to assess whether a safety-conscious work environment existed at the station. The interviews were conducted using the guidance provided in Appendix 1 of NRC Inspection Procedure 71152, Suggested Questions for Use in Discussions with Licensee Individuals Concerning Problem Identification and Resolution Issues.
In addition to the interviews, the team looked for evidence that plant employees might be reluctant to raise safety concerns during document reviews and observations of activities. The team also reviewed the station procedures related to the Employee Concerns Program (ECP), and discussed the implementation of this program with the stations program coordinator.
b.
Observations The team did not identify any significant findings. Workers generally expressed no concerns about identifying issues, and felt comfortable discussing them with supervision without fear of reprisal. The team observed that all personnel interviewed were aware of the different options through which they could express concerns including the corrective action program, informing their supervisor or plant managers, or coming to the NRC; however, many workers said they preferred reporting issues directly to their immediate supervisor.
With regards to contacting the licensees Employee Concern Program (ECP) a number of individuals interviewed by the team did not readily recognize the ECP as an avenue to raise safety concerns. A number of interviewees told the team that they thought the ECP was an avenue to address personal problems. None of the individuals interviewed had contacted ECP to raise concern or knew of anyone who had raised concerns through the ECP. The interviewed individuals expressed no concerns with utilizing it, if needed. The team noted that the number of issues being addressed in 2005 at Braidwood through the ECP was very low.
During the course of safety conscious work environment interviews with plant employees, the management decision process regarding analysis and response to observed boric acid leakage from Unit 2 D loop pressurizer spray valve 2RY455B was raised to the inspectors. As a result, the team assessed the licensees performance associated with this issue.
On December 22, 2004, following a reactor trip of Unit 2 subsequent to a failed circuit card in the Steam Generator Water Level Control circuitry a Mode 3 walk down of containment was being performed. Using procedure ER-AA-335-015 (Rev 3), VT-2 Visual Examination, and the ER-AP-331 Boric Acid Control Program series the licensee identified boric acid leakage in the vicinity of 2RY455B (IR 285241). At the time of discovery, based on As-Low-As-Reasonably-Achievable concerns and plant piping temperature concerns the licensees visual examiner recommended to management not to remove the mirror insulation on the valve and adjacent piping to confirm the exact source of the leak. The source of the leak, which was later confirmed during the subsequent Unit 2 refueling outage, was analyzed to be from the body to bonnet joint of 2RY455B based on maintenance performed on this joint during the previous refueling outage, as well as the pattern of boric acid formation on the insulation and adjacent piping and structure. Licensee procedures governing visual inspection in existence at the time of discovery, allowed for an engineering analysis to be performed in place of the required removal of insulation to verify that through-wall leakage did not exist in pressure boundary piping, and therefore no violation of NRC requirements occurred.
The team reviewed the licensees current procedures governing the Boric Acid Control Program and interviewed the engineer responsible for boric acid control, and noted that subsequent to this event, the licensee procedures have been changed to require the removal of insulation when the source of a leak involving boric acid cannot be visually verified.
4OA6 Meetings
Exit Meeting The team presented the inspection results to Mr. K. Polson and other members of licensee management on October 28, 2005. The team confirmed with the licensee that proprietary information reviewed during this inspection would not be included in the inspection report.
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee
- K. Polson, Site Vice President
G. Boerschig Plant Manager
- S. Butler, Licensing Engineer
- M. Smith, Engineering Director
- S. Butler, Acting Regulatory Assurance Manager, NRC Coordinator
- J. Feeney, NOS Assessment Manager
- F. Lentine, Design Engineering Manager
- J. Moser, Radiation Protection Manager
- G. Golwitzer, Site Corrective Action Program Manager
- D. Riedinger, Braidwood Design Engineer
- E. Johnston, Braidwood, Maintenance
- M. Morrs, Chemistry CAPCO
- T. Odette, Work Control, CAPCO
Nuclear Regulatory Commission
- N. Shah, Braidwood Acting Senior Resident Inspector
Serita Sanders, NRR/DIPM
Meghan Thorpe-Kavanaugh, NRC
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
- 05000457/2005012-01; Molded Case Circuit Breaker Testing Results
Closed
None
Discussed
NCV50-456/457/00-06-06(DRS)); Triennial Fire Protection Baseline Inspection, failure to provide any objective evidence that the molded case circuit breakers at the 120Vac and 125Vdc voltage levels had been periodically manually exercised, inspected, and tested as required by the Braidwood Stations Fire Protection Report, Chapter 2.4, Safe Shutdown Analysis.
NCV 50-456/457/03-05-02; Triennial Fire Protection Baseline Inspection Molded Case Circuit Breaker Testing failure to follow vendor and industry guideline regarding manually exercising breakers.