IR 05000454/2005008

IR 05000454-05-008 (Drp), IR 05000455-05-008 (DRP) on 06/13/2005 - 07/01/2005 for Byron Station, Units 1 and 2. Identification and Resolution of Problems

ML052210270
Person / Time
Site:	Byron
Issue date:	08/07/2005
From:	George Wilson NRC/RGN-III/DRP/RPB3
To:	Crane C Exelon Generation Co, Exelon Nuclear
References
IR-05-008
Download: ML052210270 (26)

Text

August 7, 2005

SUBJECT:

BYRON STATION, UNITS 1 AND 2 NRC PROBLEM IDENTIFICATION AND RESOLUTION INSPECTION REPORT 05000454/2005008(DRP); 05000455/2005008(DRP)

Dear Mr. Crane:

On July 1, 2005, the U.S. Nuclear Regulatory Commission (NRC) completed a team inspection at the Byron Station, Units 1 and 2. The enclosed report documents the inspection findings which were discussed on July 1, 2005, with Mr. S. Kuczynski 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 two concerns that cut across all the functional areas of the PI&R programs.

Specifically, the team identified that plant staff were sometimes too focused on the specific process being implemented rather than on the overall PI&R programs, and that operating experience, especially internal Exelon experience, was ineffectively utilized. The team also identified several examples of minor problems, including conditions adverse to quality that were not entered into the corrective actions program and narrowly focused condition report evaluations.

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/

George Wilson, Acting Chief Branch 3 Division of Reactor Projects Docket Nos. 50-454; 50-455 License Nos. NPF-37; NPF-66

Enclosure:

Inspection Report 05000454/2005008(DRP); 05000455/2005008(DRP)

w/Attachment: Supplemental Information

REGION III==

Docket Nos:

50-454; 50-455 License Nos:

NPF-37; NPF-66 Report Nos:

05000454/2005008(DRP); 05000455/2005008(DRP)

Licensee:

Exelon Generation Company, LLC Facility:

Byron Station, Units 1 and 2 Location:

4450 N. German Church Road Byron, IL 61010 Dates:

June 13 through July 1, 2005 Inspectors:

N. Shah, Acting Senior Resident Inspector R. Ng, Resident Inspector B. Jorgensen, Consultant C. Thompson, Illinois Emergency Management Agency Approved by:

George Wilson, Acting Chief Branch 3 Division of Reactor Projects

Enclosure

SUMMARY OF FINDINGS

IR 05000454/2005008(DRP), 05000455/2005008(DRP); 06/13/2005 - 07/01/2005; Byron

Station, Units 1 and 2. Identification and Resolution of Problems.

The inspection was conducted by an acting senior resident inspector, a resident inspector, a State of Illinois resident engineer, and a consultant. 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 two concerns that cut across all the functional areas (problem identification, evaluation and resolution) of the corrective actions program.

Specifically, the team identified that plant staff were sometimes too focused on the specific process being implemented rather than on the overall program. There were several instances where issues were identified during cause or operability evaluations, but were not fed back into the corrective action program, because it was not a specific requirement of the evaluation process. The team also noted that industry experience, especially internal Exelon experience, was underutilized in identifying or evaluating issues. The Nuclear Oversight organization was considered intrusive and challenged corrective action program performance based on the numerous examples of assessment findings reviewed during the inspection. The team also observed that the station had reasonably addressed previously identified NRC issues, but noted that Nuclear Oversight had identified some concerns with the corrective actions for those issues identified during the 2003 NRC Problem Identification and Resolution inspection.

REPORT DETAILS

4OA2 Problem Identification and Resolution

.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 handbooks, 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 selected operator logs generated during the inspection period and during the previous Unit 1 refueling outage (February 27-March 25, 2005) to determine whether identified issues were being captured in the CAP.

The team reviewed previous licensee and inspector-identified issues, operating experience reports, Nuclear Oversight (NOS) and trend assessments to determine if problems were being identified at the appropriate threshold and entered into 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 05000454/2003009(DRP); 05000455/2003009(DRP)) for more in-depth review.

The team performed an in-depth review of the emergency diesel generator (DG) and auxiliary feedwater systems to evaluate the licensees processes for equipment monitoring, maintenance rule implementation, and to identify if issues were being appropriately addressed. Both 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 items or 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 two systems described above, the team also reviewed issue reports (IRs) generated since January 1, 2004, for the switchyard, pressurizer and reactor coolant systems for potential trends.

The team reviewed selected audits and self-assessments of the corrective actions, operations, maintenance, engineering and plant support (radiation protection, chemistry, emergency preparedness and security) 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 IR for any item they personally felt needed attention or action.

Very large numbers of issues were entered into the computer database for the CAP; approximately 10,000 items were entered since January 1, 2004. The team noted that the majority of these IRs were of very low individual significance.

Although the team concluded that problems were being adequately identified, there were some vulnerabilities noted involving potential information lost to the CAP and some examples where new issues arose during the cause evaluation that were not captured in the CAP. These matters are discussed in greater detail below.

b.1 Observations on Thresholds for Entering Known Problems into the Corrective Action Program As noted, all individuals were encouraged to initiate an IR for any issue they felt needed attention. 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. During interviews, most station staff stated that reporting an issue was less likely to bring trouble than knowing about an issue and not reporting it. Still, the team observed a considerable variation in the level of direct participation in the program. For example, in several departments, working-level individuals preferred to report problems to first line supervision, rather than initiate an IR themselves. The team noted that this practice was consistent with the CAP procedures and did not appear to deprive the CAP of issues which needed to be addressed.

However, the team did identify some potential vulnerabilities where issues could be lost to the CAP process:

• Many departments maintained an informal issues list. These lists resulted from a senior management initiative and were supposed to monitor items outside the scope of the CAP, such as work efficiency or quality of life issues. Most issues tracked on these lists did not warrant an IR and for those few that did, an IR had been initiated, all though this was not always reflected on the lists. Still, the team was concerned with the informality of these lists, including the lack of cross-referencing to the CAP.

• During the interviews, many workers stated that minor issues associated with human performance or with work package or procedural quality, were generally fixed in the field rather than through the CAP. Although contrary to management expectations, workers felt that this was preferable. The practice reflected a preference for continuation of work and, with respect to human performance, a general unwillingness to report on a fellow worker. While the few examples provided by the workers were truly minor in nature, this was considered a vulnerability because of the potential for issues to not be captured in the CAP and because the threshold for what constituted a minor issue was being established at the worker level.

The team noted that Braidwood IRs were distributed during the daily plan-of-the-day meetings, but that there was no expectation that these IRs be fully evaluated. In fact, with the exception of operations, the department CAP coordinators typically did not screen the Braidwood IRs for applicability to Byron station. However, the team noted that system engineers were required to review these IRs for system applicability and that this expectation was being met. Given the similarity between the two stations, it was probable that many issues identified at Braidwood would be applicable to Byron.

The failure to use the Braidwood IRs was considered one example of a general tendency to underutilize industry experience, which the team considered a weakness in the CAP.

Issues identified in the operator logs were appropriately documented in IRs, and potential operability concerns were generally routed to operations shift management for review. However, there were some examples where this had not occurred:

• IR 244846 documented an Apparent Cause Evaluation (ACE) following a trip of the 0A train of control room ventilation on August 16, 2004. The cause was identified as a short-to-ground of the fan motor windings, which was stated to be a known industry issue with Reliance motors. The team noted that at the time of discovery, there was no documented evaluation regarding the operability of the 0B train of control room ventilation. Additionally, during a subsequent evaluation, engineering identified that this same issue potentially affected other safety-related motors currently in use, yet there was no indication that this information was ever communicated to operations for review.

• IR 310377 identified that on March 24, 2004, the 1A main steam isolation valve room ventilation damper solenoid was found stuck in the energized position, when the room fan was shutdown, resulting in the outside air damper failing open rather than closed. Although the solenoid is not safety-related, the effects of operability on safety-related components in the room were not evaluated for the environmental conditions resulting from this configuration.

In these examples, station engineering had reasonably concluded that the operability of the affected components was not challenged, but had failed to recognize that only licensed operations staff could make this determination. This was one example of a general theme where workers failed to consider the overall CAP, because they were too focused on a particular process. While no violations were identified, this was considered a weakness with the CAP.

b.2 Observations and Findings on Identifying Conditions Adverse to Quality The team identified several examples where new issues were identified during cause or operability evaluations which were not captured in the CAP. These issues were minor in nature and did not constitute violations of NRC requirements. Some examples included:

• The ACE following the trip of the 0A train of control room ventilation (IR 244846),identified the cause as a short-to-ground of the fan motor windings. Although the evaluation stated that this was a known industry issue with the manufacturer of these motors, there was no discussion or subsequent action to determine why this known issue had not been previously addressed by the licensee.

• A Root Cause Report (RCR) (IR 208018) addressing several occurrences of procedural adherence issues at the station, identified that similar problems were also present with Nuclear Station Procedures and with Training and Reference Materials. However, there was no discussion or subsequent action to address this issue. Additionally, the report identified that the licensee had not evaluated operating experience from LaSalle station documenting similar procedural adherence issues, but again, it did not appear that this missed opportunity was ever evaluated.

• An Operability Evaluation (IR 318009) for a through wall leak identified in a fire header on March 28, 2005, stated that this was the second such leak in the same section of piping since 2002. However, there was no indication that the reason for the recurrent leakage was ever evaluated. During the inspection, the team noted that station operations had raised a similar question during a Plan-of the-Day meeting, but again, no formal action was taken to review the issue.

• An Operability Evaluation (IR 334573) for observed leakage from the 1B centrifugal charging pump inboard bearing, identified the potential cause as improper clearance in the labyrinth seal due to prior work occurring in the thirteenth Unit 1 refueling outage. However, this conclusion was not fed back into the CAP process for consideration by those staff performing the root cause evaluation. The operability evaluation also identified that the Updated Final Safety Analysis Report implied that the mission time of the charging pump was 1 year, but that the actual mission time was 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, per a corporate letter dated July 26, 1996. However, no action was taken to determine why the Updated Final Safety Analysis Report had not been updated to reflect the actual mission time.

These examples provided further evidence that workers were often too focused on specific processes to consider the overall CAP. For example, the individual performing the above operability evaluations, stated that he had not written IRs to address the new issues, because it was not a formal requirement of the evaluation process. As stated previously, this was a pervasive issue that was considered a weakness by the team.

b.3 Selected System Reviews In general, observed equipment deficiencies had been entered into the corrective action program and selected operating experience reports were properly evaluated and dispositioned by the system engineer. The team concluded that the operability evaluations reviewed provided adequate evaluation and justification of operability issues. Based on the sample of issue reports reviewed, the team also concluded that issues affecting equipment availability were appropriately evaluated for maintenance rule applicability.

The team observed that there had been numerous IRs and work tags written for oil related issues on both the emergency DG and auxiliary feedwater systems. For example, since May 2002, there were approximately 24 IRs or work requests concerning oil related issues on either the 1B or 2B diesel driven auxiliary feedwater pumps. These issues were being tracked by the licensee individually, and none of them presented an operability concern. However, the team noted that while individual oil leaks were reasonably tracked, oil consumption was not. Further review determined that this was a generic issue for all plant systems. Although operations maintained an oil addition log, it was not a formal process, was often not updated by plant operators and was not reviewed by system owners. The team noted that changes in oil leak rates were typically identified either after the leakage had increased significantly or through tribal knowledge. This was considered a potential vulnerability as it too often placed the station in a reactive rather than a proactive mode in addressing oil leakage.

The team noted that there had been a significant decline in the performance of the auxiliary feedwater system in the last 2 years. Specifically, several events occurred which compromised the system performance capabilities. In March, 2004, the system was placed in Maintenance Rule (a)(1) status due to repetitive lubricating oil low level events occurring in December 2003 and January 2004. Other events included overheating of the 2B auxiliary feedwater pump diesel engine due to a lack of jacket water in April 2004, and loss of cooling to the 1A auxiliary feedwater pump oil coolers in June 2004. During subsequent evaluations, the licensee identified that two of these events (i.e., the loss of lube oil level and the loss of cooling flow to oil coolers) were avoidable, had information concerning industry practices and experience been fully utilized in risk prevention or in issue evaluation. In particular, practices at other Exelon sites, had they been adopted at Byron, likely would have prevented these events. This was considered an example where industry experience, especially internal Exelon experience, was ineffectively utilized.

The team also observed that the licensees initial evaluation following the 2B auxiliary feedwater pump jacket water overheating, was focused more on proving operability of the pump instead of determining the extent of potential damage to the diesel. Specific technical information (such as how low the jacket water got, how long the 2B pump diesel ran in this condition and how hot the engine eventually got) was not addressed.

Additionally, the evaluation did not identify what the most vulnerable component was and how to inspect for damage. This initial evaluation assumed that the water jackets were not empty, but under-filled. In a subsequent more in-depth evaluation, using the same information that existed at the time of overheating, the licensee determined that the water jackets were more likely empty, a highly significant difference.

b.4 Nuclear Oversight Overall, NOS was conducting well-planned, thorough audits and was identifying numerous findings and observations across the spectrum of performance, including issues of proper CAP 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 CAP was broader in scope and more critical than the licensees subsequent, April 25, 2005, CAP 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 illustration of broad organizational weaknesses. Instead, as noted for other organizations, 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 Apparent Cause Evaluations, Root Cause Reports, prompt investigations, operability determinations, and Common Cause Analyses. Attributes reviewed included the technical adequacy of the cause determinations, 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 data for a 5 year period for the emergency DG and auxiliary feedwater systems. The team evaluated whether identified issues were appropriately prioritized and evaluated when entered into the corrective action program. In particular, the team focused on whether functional failures and system unavailability time were appropriately identified and tracked in accordance with the maintenance rule. Those issues having cause evaluations were reviewed as described above.

Other attributes reviewed by the team included the quality of the licensees trending of conditions and the corresponding corrective actions. The team searched for items or issues which looked like potential trends and assessed whether the licensee had appropriately identified and captured these trends within the corrective action program.

The team also assessed licensee corrective actions stemming from previous Non-Cited Violations and Licensee Event Reports.

The team reviewed the various controlling procedures, selected records of activities, walkdowns of the selected systems, interviews with cognizant station personnel and observation of various licensee meetings. The specific documents reviewed are listed in the Attachment to this report.

b. Observations and Findings

b.1 Evaluations In general, the licensees evaluations were found to be broadly-based, technically sound, and focused on safety. However, the team identified some problems with the effectiveness of trend evaluations and additional examples where workers failed to consider the overall CAP when implementing specific processes or failed to effectively utilize industry experience. No violations of NRC requirements were identified.

b.2 General Corrective Action Program Implementation Observations The licensees program had built-in mechanisms for identifying or recognizing conditions adverse to quality. As noted, the program authorized and encouraged all staff to initiate IRs as appropriate. Once initiated, IRs were first reviewed by the department CAP coordinators for completeness and for assignment of the applicable trend coding. The IRs were then reviewed by the Station Ownership Committee to assign priority and actions. Issues potentially bearing on plant equipment operating conditions or otherwise having the potential to affect plant operations were promptly routed to the operating shift for review by the Shift Manager. Selected issues were then reviewed by the station Management Review Committee, comprising senior managers from each department, to verify that the overall CAP objectives were being met.

The team attended several Station Ownership Committee and Management Review Committee meetings and observed that issues were being appropriately challenged and that reportability, repetitiveness and trending were discussed where appropriate.

Additionally, there were no instances of significant disagreement with the priority classification or disposition of the corrective action documents at the meetings attended by the team. Through interviews, the team noted that the department CAP coordinators were generally stable without major turnover. This stability allowed for a more consistent application of trend codes and trend analysis within departments. Generally, issues were clearly identified in the IRs and supporting information was well documented.

Each department CAP coordinator prepared trend reports on an approximately quarterly basis. These reports normally addressed the preceding 6 months, so they overlapped by 2 or 3 months. Therefore, data in various standardized categories (significant issues, human error precursor and defense, process issues, and others) was thus reported for the same months in two successive reports.

The team identified numerous examples where the same categories contained inconsistent conclusions in different trending periods. For example, the engineering department Quarterly Trend Analysis reports for March to August 2004 and for July to December 2004, had different values for the number of significant level 3 issues for July and August 2004, respectively. Similar issues were also identified in maintenance department trend reports generated in August 2004 and January 2005, in that both listed different totals for the number of significant issues identified in July and August 2004, respectively. This inconsistency in the database occurred throughout all the department quarterly trend reports reviewed. The team could not identify the cause of the disparities, but noted, in some cases, that they apparently resulted from errors in setting up the trend report search in the licensees CAP database. However, given the pervasiveness of the inconsistencies, the team questioned the validity of the trending process and the associated conclusions. IR 347320 was generated by the licensee to document this issue.

The team identified some examples where it was unclear if the cause of the potential trends had been evaluated. For example:

• An engineering evaluation (IR 311441), for an adverse trend with seizing of velan globe valves on safety-related cubicle coolers, identified the cause as binding of the valve stem with the bonnet bushing. However, there was no discussion on how this conclusion was reached, what was causing the binding, or whether other Exelon sites had experienced similar problems. Subsequently, the team learned that the system engineer had inspected some of the bound valves and believed the cause was corrosion of the valve internals due to the raw water environment. The engineer also stated that other Exelon sites had not had similar problems, possibly due to more frequent cycling of the valves than at Byron. However, as stated these observations were not discussed in the trend evaluation.

• An engineering evaluation (IR 297670) for an adverse trend with 1A centrifugal pump cubicle cooler flow, stated that the cubicle flow was restored following maintenance on the cubicle cooler flow valves and flushing of the cooler service water flow instrumentation line. However, the reason for the trend was not evaluated, so it was unclear whether these repairs corrected the symptom or the cause.

The team determined that the failure to properly document or fully evaluate the cause of these trends was a weakness, as it limited the efficacy of the process.

The team observed that industry experience was appropriately captured in the CAP, but noted that the review for applicability was often limited. For example, the licensees evaluation of a Clinton Nuclear Event Report (IR 206997) describing problems with the electro hydraulic control system during plant startup, concluded that no action was warranted as Byron used a different system. However, the focus of this evaluation was limited to the applicability of the corrective actions described in the Event Report and not on the root or contributing causes of the event. These causes were potentially applicable, as they were independent of the type of electro hydraulic control system being used. The team noted that the licensees process for evaluating operating experience only required that the corrective actions and not the causes be reviewed.

This was another example where the focus on a specific process limited the overall efficacy of the CAP.

Other examples of problems with the use of industry experience included:

• An apparent cause evaluation (IR 274453) for an inadvertent drain down of the Unit 1 spent fuel pool during resin transfer operations, did not address a similar event occurring at another Exelon site approximately 1 year earlier. This event had similar root and contributing causes, and the corrective actions may have prevented the subsequent Byron event.

• An operability evaluation (IR 334573), for oil leakage from the 1B centrifugal charging pump inboard bearing, referenced another evaluation (IR 111324) for a similar issue involving the Braidwood 2B centrifugal charging pump. The Braidwood evaluation stated that the oil leakage was aggravated by a vacuum effect caused by the pump coupling guard, which was fixed by slotting the guard.

However, this vacuum effect was not considered in the Byron operability evaluation or otherwise captured in the CAP.

• The team noted that IR 306538, a Byron event involving a failure to declare a Notice of Unusual Event, was in part due to a failure to thoroughly evaluate internal Exelon experience, specifically an earlier issue with dose equivalent iodine at Braidwood, such that the potential for the expected transient to reach reportability levels was not recognized.

• The team noted the occurrence of several preventable security events involving ammunition control, vehicle accidents and a mis-operation of an Active Vehicle Barrier, which had in common, a failure by the licensee to adequately consider industry experience, including internal Exelon events.

As stated earlier (Section 1.b.3), the team also noted that several of the auxiliary feedwater pump events had a common cause in that information concerning industry practices and experience was not fully utilized in risk prevention or in issue evaluation.

These examples provided further evidence of a general tendency to underutilize industry experience, in identifying or evaluating issues at Bryon.

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 verified the appropriate implementation of a sample of corrective actions and reviewed a sample of corrective action effectiveness reviews completed by the licensee. The selection of samples for review were based on their importance in reducing operational risks and recurring problems.

The team focused on information recorded since the 2003 PI&R inspection, but did review selected items going back over a 5-year period. The team selected samples based on their importance in reducing operational risks and recurring problems. 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. However, there were some examples where past corrective actions were not fully addressed in issue evaluations. For example:

• A root cause evaluation (IR 208018) for procedural adherence issues, identified that the licensee had performed evaluations for prior, similar issues at both Dresden (IR 165123) and Byron (IR 166546). However, there was no discussion on whether the corrective actions from these earlier evaluations should have prevented recurrence.

• The apparent cause evaluation for the inadvertent drain down of the Unit 1 spent fuel pool, identified several, prior fleet events including one at Byron (IR 215585).

However, the evaluation did not discuss whether the corrective actions from these events should have prevented this issue.

As stated, the team did not consider this a pervasive problem, but noted that further station attention was needed to determine the efficacy of previous corrective actions.

In general, the station had effectively addressed previously identified Non-Cited Violations, but the team noted that NOS had raised concerns about how the station addressed issues identified in the 2003 PI&R inspection. In particular, NOS was concerned with the timeliness of corrective actions for the centrifugal charging pump shaft failures and whether the corrective actions for the reactor containment fan cooler switch were in variance from the issues raised in the NRC report. The team did not identify any issues with the licensees handling of those Licensee Event Reports reviewed during this inspection.

Many workers expressed frustration that, in general, low level issues may remain uncorrected for extended periods of time, in part due to increasing workload and diminishing resources to address identified issues. However, no one identified an example of staff inability or unwillingness to raise and document safety concerns due to inadequate time or resources. This observation was also documented in the 2003 NRC inspection report. The team identified the following examples of prolonged inaction on issues assigned a low priority:

• The essential service water SX101 valves, which supplied cooling water to the auxiliary feedwater pump oil coolers, were identified as problematical, in as early as 1995 when a valve failed at another Exelon site. Although preventive maintenance (coil replacement, cleaning of internals) was instituted at another Exelon site, similar proposals at Byron (in 1998 and 2003) and a separate proposal to remove the valves from the system (in 2000), received no action. It wasnt until a valve failed at Byron in 2004, that their removal from the system was approved.

• IR 139856 described a procedural use and adherence deficiency when an electrical maintenance technician discovered that a chart recorder and jumpers for recording the local 2B emergency DG control panel were disconnected. The chart recorder had originally been installed by electrical maintenance, but had been removed by operations. The cause was inadequate guidance regarding who was responsible (maintenance or operations) for installing/removing the chart recorders. The corrective action was to revise the applicable procedures to assign overall responsibility of the chart recorders to electrical maintenance.

This action was initiated in November 2003, but was not completed until July 2005. The team felt that the time to correct this relatively minor problem was excessive, given that there were several other revisions to this procedure, addressing similar minor concerns during this period.

Although none of these examples were violations, they did provide some credence to the workers concerns. They also, in part, contributed to the feelings of frustration that resulted in some workers fixing minor problems outside of the CAP (Section 1.b.1)

.4 Assessment of Safety-Conscious Work Environment

a. Inspection Scope

The team interviewed approximately 33 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 avenues through which they could express concerns including the corrective action program, informing their supervisor or plant managers, contacting the ECP coordinator, or coming to the NRC; however, many workers said they preferred reporting issues directly to their immediate supervisor.

Workers were generally familiar with the ECP and expressed no concerns with utilizing it. In fact, the team noted that the number of issues being addressed in 2005 to date at Byron, was significantly higher than the sum total of all ECP issues identified at the other Exelon sites since January 2004. Neither the team nor the licensee understood the reason for the disparity, but attributed it, in part, to better advertising of the ECP program at Byron. The team did not identify any common concerns or trends among the issues being tracked at Byron.

4OA6 Meetings

Exit Meeting The team presented the inspection results to Mr. S Kuczynski and other members of licensee management on July 1, 2005. The team confirmed with the licensee that proprietary information was not examined during the inspection.

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

S. Kuczynski, Site Vice President

B. Adams, Engineering Manager

R. Chalifoux, CAP Coordinator

R. Choinard, Regulatory Assurance

D. Chrzanowski, Cantera Licensing

W. Grundmann, Regulatory Assurance Manager

T. Fluck, Regulatory Assurance

S. Kerr, Chemistry Manager

B. Kouba, Nuclear Oversight Manager

M. Prospero, Operations Manager

B. Youman, Maintenance Manager

Illinois Emergency Management Agency

C. Thompson, Illinois Emergency Management Agency Resident Engineer

Nuclear Regulatory Commission

R. Skokowski, Byron Senior Resident Inspector

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

None

Discussed

None