IR 05000454/2011008

IR 05000454-11-008 & 05000455-11-008, on 08/15/2011 - 09/02/2011, Byron Station, Units 1 and 2, NRC Identification and Resolution of Problems

ML112910140
Person / Time
Site:	Byron
Issue date:	10/17/2011
From:	Eric Duncan Region 3 Branch 3
To:	Pacilio M Exelon Generation Co, Exelon Nuclear
References
IR-11-008
Download: ML112910140 (39)

Text

ober 17, 2011

SUBJECT:

BYRON STATION, UNIT 1 & 2 NRC PROBLEM IDENTIFICATION AND RESOLUTION INSPECTION REPORT 05000454/2011008; 0500455/2011008

Dear Mr. Pacilio:

On September 2, 2011, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Byron Station. The enclosed inspection report documents the inspection results, which were discussed on September 7, 2011, with Mr. B. Adams and other members of your staff.

The inspection examined activities conducted under your license as they relate to safety and compliance with the Commission=s rules and regulations and with the conditions of your license.

The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.

On the basis of the samples selected for review, the team concluded that in general, problems were properly identified, evaluated, and corrected. Two NRC-identified findings of very low safety significance (Green) associated with procedure adherence and untimely corrective actions were identified. These findings were determined to involve violations of NRC requirements. However, because of their very low safety significance and because the issues were entered into your corrective action program, the NRC is treating these violations as non-cited violations (NCVs) in accordance with Section 2.3.2 of the NRC Enforcement Policy.

In addition, several examples of minor problems were identified, including weaknesses in the trending of procedural issues and long-standing open corrective action assignments.

If you contest the subject or severity of a non-cited violation, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001, with a copy to the Regional Administrator, U.S. Nuclear Regulatory Commission - Region III, 2443 Warrenville Road, Suite 210, Lisle, IL 60532-4352; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the Resident Inspector Office at the Byron Station. In addition, if you disagree with the characterization of any finding in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region III, and the NRC Resident Inspector at the Byron Station. The information you provide will be considered in accordance with Inspection Manual Chapter 0305. In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of the NRC=s document system (ADAMS). ADAMS is accessible from the NRC Website at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Eric R. Duncan, Chief Branch 3 Division of Reactor Projects Docket Nos. 50-454; 50-455 License Nos. NPF-37; NPF-66

Enclosure:

Inspection Report No. 05000454/2011008 and 05000455/2011008 w/Attachment: Supplemental Information

REGION III==

Docket Nos: 50-454; 50-455 License Nos: NPF-37; NPF-66 Report Nos: 05000454/2011008 and 05000455/2011008 Licensee: Exelon Generation Company, LLC Facility: Byron Station, Units 1 and 2 Location: Byron, IL Dates: August 15, 2011, through September 2, 2011 Team Leader: R. Ng, Project Engineer Inspectors: J. Robbins, Resident Inspector C. Brown, Reactor Inspector D. Jones, Reactor Engineer C. Thompson, Resident Inspector, Illinois Emergency Management Agency Approved by: E. Duncan, Chief Branch 3 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

IR 05000454/2011008; 05000455/2011008; 08/15/2011 - 09/02/2011; Byron Station, Units 1 and 2; Identification and Resolution of Problems.

This inspection was performed by region-based inspectors, the Byron Resident Inspector, and the Byron Illinois Emergency Management Agency (IEMA) resident inspector. Two NRC-identified Green findings with associated Non-Cited Violations (NCVs) of NRC requirements were 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). Assigned cross-cutting aspects were determined using IMC 0310, Components Within the Cross-Cutting Areas. Findings for which the SDP does not apply may be Green or be assigned a severity level after NRC management review. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 4, dated December 2006.

Identification and Resolution of Problems On the basis of the samples selected for review, the team concluded that, overall, the corrective action program (CAP) at Byron Station was effective in identifying, evaluating and correcting issues. The licensee had a low threshold for identifying issues and entering them into the CAP.

Issues entered in the CAP were properly prioritized and evaluated based on plant risk and uncertainty. Corrective actions were generally implemented in a timely manner, commensurate with safety significance. Operating Experience (OPEX) was entered into the CAP and appropriately evaluated. The use of OPEX was integrated into daily activities and found to be effective in preventing similar issues at the plant. In addition, the licensees self-assessments, audits, and effectiveness reviews were found to be conducted at appropriate frequencies for all departments. The assessments reviewed were thorough and effective in identifying site performance deficiencies, programmatic concerns, and improvement opportunities. On the basis of the interviews conducted, the inspectors did not identify any issues that suggested conditions were not conducive to the establishment and existence of a Safety Conscious Work Environment (SCWE) at Byron Station. The staff was aware of and generally familiar with the CAP and other station processes, including the Employee Concerns Program (ECP), through which concerns could be raised.

There were two Green findings, each with an associated NCV, identified by the team during this inspection. A Green finding with two examples was identified that concerned the licensees failure to implement corrective actions in a timely manner to address previously identified NRC violations. A second Green finding identified was related to the licensees failure to initiate Issue Reports (IRs), as required by licensee procedures, to address potential equipment operability issues. The team also identified several examples of minor issues, including weaknesses in the trending of procedural issues and long-standing open corrective action assignments.

NRC-Identified

and Self-Revealed Findings

Cornerstone: Mitigating Systems

• Green: The inspectors identified a finding of very low safety significance and an associated NCV of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, when licensee personnel failed to implement timely corrective actions to address two previously issued NCVs. The two NCVs were related to the lack of design analysis documentation associated with the Recycle Holdup Tank (RHUT); and tornado missile and seismic protection for the Diesel Oil Storage Tank (DOST) vent lines.

Specifically, the licensee had not completed required design analyses for these issues at the conclusion of this inspection, although the violation associated with the RHUT was initially identified by NRC inspectors in June 2007 and the violation associated with the DOST vent lines was initially identified by NRC inspectors in February 2009. The licensee entered this issue into their CAP as IR 1269928 and planned to complete the required analyses by April 2012.

This finding was of more than minor significance because the issue was associated with the Mitigating Systems Cornerstone attribute of Equipment Performance and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). The inspectors determined the finding could be evaluated using the SDP in accordance with IMC 0609, Significance Determination Process, Attachment 4, Phase I - Initial Screening and Characterization of Findings, Table 4a for the Mitigating Systems Cornerstone and answered No to all the Mitigating Systems Cornerstone questions. Specifically, the issue did not result in the actual loss of the operability or functionality of a safety system.

Therefore, the finding screened as having very low safety significance (Green).

This finding had a cross-cutting aspect in the Resources component of the Human Performance cross-cutting area (H.2(a)) because the licensee failed to maintain long-term plant safety through minimization of long-standing equipment issues.

(Section 4OA2.1.b.3.i)

Green.

The inspectors identified a finding of very low safety significance and an associated NCV of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, when licensee personnel failed to initiate IRs during the review of OPEX in accordance with licensee procedures to ensure that immediate actions, operability determinations, and reportability concerns were addressed by shift management within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The licensee entered this issue into the CAP as IR 1257548 and completed the required shift management review.

The finding was of more than minor significance because, if left uncorrected, the issue would have the potential to lead to a more significant safety concern. The inspectors determined the finding could be evaluated using the SDP in accordance with IMC 0609, Significance Determination Process, Attachment 4, Phase I - Initial Screening and Characterization of Findings, Table 4a for the Mitigating Systems Cornerstone and answered No to all the Mitigating Systems Cornerstone questions.

Specifically, the issue did not result in the actual loss of the operability or functionality of a safety system. Therefore, the finding screened as having very low safety significance (Green). This finding had a cross-cutting aspect in the Operating Experience (OPEX) component of the Problem Identification and Resolution (PI&R)cross-cutting area (P.2(a)) because the licensees procedures and guidance for OPEX did not ensure the systematic collection, evaluation, and communication to affected internal stakeholders, in a timely manner, of relevant internal and external OPEX. (Section 4OA2.2.c)

Licensee-Identified Violations

None.

REPORT DETAILS

4OA2 Problem Identification and Resolution

This inspection constituted one biennial sample of Problem Identification and Resolution (PI&R) as defined by Inspection Procedure 71152, Problem Identification and Resolution. Documents reviewed are listed in the Attachment to this report.

.1 Assessment of the Corrective Action Program Effectiveness

a. Inspection Scope

The inspectors reviewed the procedures and processes that described Exelons Corrective Action Program (CAP) at Byron Station to ensure, in part, that the requirements of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, were met.

The inspectors observed and evaluated the effectiveness of meetings related to the CAP, such as Station Ownership Committee and Management Review Committee (MRC) meetings. Selected licensee personnel were interviewed to assess their understanding of and their involvement in the CAP.

The inspectors reviewed selected Issue Reports (IRs) across all seven Reactor Oversight Process (ROP) Cornerstones to determine if problems were being properly identified and entered into the licensees CAP. The majority of the risk-informed samples of IRs reviewed were issued since the last NRC biennial PI&R inspection conducted in August of 2009. The inspectors also reviewed selected issues that were more than 5 years old.

The inspectors assessed the licensees characterization and evaluation of the issues and examined the assigned corrective actions. This review encompassed the full range of safety significance and evaluation classes, including root cause evaluations, apparent cause evaluations, and workgroup evaluations. The inspectors assessed the scope and depth of the licensees evaluations. For significant conditions adverse to quality (SCAQs), the inspectors evaluated the licensees corrective actions to prevent recurrence and for less significant issues, the inspectors reviewed the corrective actions to determine if they were implemented in a timely manner commensurate with their safety significance.

The inspectors selected the auxiliary building ventilation (VA) system to review in detail since VA was a Maintenance Rule (a)(1) system. The primary purpose of this review was to determine whether the licensee was properly monitoring and evaluating the performance of Maintenance Rule systems through effective implementation of station monitoring programs. The inspectors interviewed the VA system engineer, reviewed numerous VA-related IRs, and reviewed root cause evaluations associated with the VA system. A 5-year review of VA issues was performed to assess the licensees efforts in monitoring for system degradation due to aging. The inspectors also performed walkdowns, as needed, to verify the resolution of issues.

The inspectors reviewed the licensees CAP trend analysis and independently performed a 5-year review of human performance trend data focusing on CAP documents that identified, through trend codes, procedural issues as a contributing cause to determine if issues were adequately characterized to identify adverse trends or repetitive issues.

The inspectors examined the results of self-assessments of the CAP completed during the review period. The results of the self-assessments were compared to self-revealed and NRC-identified findings. The inspectors also reviewed the corrective actions associated with previously identified NCVs and findings to determine whether the station properly evaluated and resolved those issues. The inspectors performed walkdowns, as necessary, to verify the resolution of the issues.

The inspectors performed an in-depth review of the stations Measurement and Test Equipment (M&TE) program since systematic weakness of this program, if they existed, could potentially affect numerous mitigating systems.

b.

Assessment

(1) Identification of Issues The inspectors concluded that, in general, the station continued to identify issues at a low threshold by entering them into the CAP. The inspectors determined that the station was appropriately screening issues from both NRC and industry Operating Experience (OPEX) at an appropriate level and entering them into the CAP when applicable to the station. The inspectors also noted that deficiencies were identified by external organizations (including the NRC) that had not been previously identified by licensee personnel.

The inspectors determined that the station was generally effective at trending low level issues to prevent larger issues from developing. The licensee also used the CAP to document instances where previous corrective actions were ineffective or were inappropriately closed.

i) Observations:

Trend Analysis Overall, site performance continued to trend in a positive direction. The composite error rate trend data for errors per 10,000 hours0 days <br />0 hours <br />0 weeks <br />0 months <br /> worked was routinely below the site goal of three. The individual performance of the operations, maintenance, and engineering departments all contributed to an overall improvement in site performance.

One of the methods utilized by the site to measure and identify plant performance was the trending of CAP data. Trend codes were assigned to each CAP document with a significance level between 1 and 4; 1 being issues of high significance or time sensitive and 4 being low significance or not time sensitive. The minimum set of trend codes included data related to the method of discovery, event type, associated process, and department/organizational identifiers. This data was collected over time and subjected to various analyses.

Numerous analysis reports were available and routinely published facilitating identification of adverse performance trends. The nature of the analyses was such that much of it was automated. Software was used to determine if data had changed in a statistically significant manner. The current reports supported the identification of trends, but were not identifying performance issues that were not changing. For example, if a given parameter was neither improving nor degrading, the current reports would not draw attention to this parameter. This was the case whether performance exceeded expectations and was steady or was below expectations and was steady. The licensee acknowledged this weakness and entered this issue into the CAP as IR 1260159.

The inspectors selected event codes associated with procedures for further assessment. Due to changes in coding methodology, the inspectors focused on the last 11 quarters of data, dating back to January 2009. The three codes selected were Procedure Adherence, Procedure Inadequate, and Process Inadequate.

There were approximately 1700 CAP documents coded with these three codes over the 11 quarters reviewed. The inspectors held discussions with members of the licensee staff to understand the breadth of issues that were characterized under the Procedure Inadequate and Process Inadequate codes specifically.

The current coding categories did not provide a method for differentiating between items that one might characterize as editorial changes, items one might characterize as enhancements, and items one might characterize as warranting placing the procedure on hold. Therefore, under the current methodology, data regarding the relative strength or weakness of procedures and their contribution to plant issues could be misleading.

The licensee acknowledged this weakness and entered this coding issue into the CAP as IR 1268584.

(2) Prioritization and Evaluation of Issues The inspectors concluded that the station was generally effective at prioritizing and evaluating issues commensurate with the safety significance of the identified issue.

The inspectors determined that the MRC CAP review meeting was generally thorough and maintained a high standard for evaluation quality. Members of the MRC discussed the issues presented in sufficient detail and challenged presenters regarding their conclusions and recommendations.

The inspectors determined that the licensee was generally effective at evaluating equipment functionality requirements after a degraded or non-conforming condition was identified. The inspectors reviewed Maintenance Rule action plans and issue reports associated with the VA system. A number of deficiencies were identified in the last 5 years, which resulted in the system entering into a Maintenance Rule (a)(1) status.

The licensee developed an action plan to resolve the deficiencies and appropriately adjusted the actions when new issues were discovered.

i) Observations:

The inspectors identified that there were a large number of open IRs at the time of the inspection. More than 12 percent of the open IRs were greater than 1000 days old. One IR originated in 2002 and still had incomplete actions. The inspectors reviewed a sample of these open IRs and determined that most of the remaining actions were enhancements and the due dates for the actions had been extended a number of times due to resource limitations or other emergent issues. The inspectors verified that the sampled IRs were evaluated and actions assigned appropriately.

However, in one case, the inspectors identified that the licensee misclassified a corrective action as an enhancement. This issue was related to a design calculation error of a support for the non-essential service water system. The inspectors determined that this issue was minor since it did not involve a safety-related system and the failure of the support would not affect other safety-related systems.

The inspectors regarded this aging IR issue as an improvement opportunity since the outstanding actions, although being considered enhancements, could potentially affect the licensees focus on more important safety issues and complicate trending analyses and resource utilization.

(3) Effectiveness of Corrective Action The inspectors concluded that corrective actions for identified deficiencies were generally timely and adequately implemented, commensurate with their safety significance. Problems identified using root or apparent cause methodologies were resolved in accordance with the CAP and applicable procedural requirements.

Corrective actions designed to prevent recurrence were generally comprehensive, thorough, and timely. The inspectors sampled corrective action assignments for selected NRC-documented violations and determined that actions assigned were generally effective and timely.

However, the inspectors identified a relatively large number of outstanding corrective action assignments. Prior to this inspection, the licensee also identified this negative trend and investigated the issue. Licensee personnel stated that the primary reasons for the large number of open corrective actions were resource limitations and the development of emergent issues warranting more immediate attention. The inspectors subsequently selected the open corrective actions that were over 1000 days old to review for timeliness. The inspectors concluded that most of these corrective actions were timely due to the relatively long lead time required for modification or for NRC approval. However, the inspectors did identify two examples of untimely corrective actions that was the subject of a Green finding as described below.

i) Findings Untimely Corrective Actions for Previously Identified Non-Cited Violations

Introduction:

The inspectors identified a Green finding and an associated NCV of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, when licensee personnel failed to implement timely corrective actions to address two previously issued NCVs.

Description:

As documented in NRC Inspection Report 05000454/455/2008009, dated November 12, 2008, NCV 05000454/455/2008009-02 was issued when licensee personnel failed to adequately evaluate and maintain the required water volume in the Recycle Holdup Tank (RHUT) necessary to quench the design basis Residual Heat Removal (RHR) system relief valve discharge into the RHUT, incorporate appropriate minimum RHUT level requirements into the RHUT level control procedure, and evaluate the effect of dynamic water hammer loads on RHUT inlet piping resulting from relief valve discharges into the RHUT. This issue was initially identified by the NRC in June 2007. The licensee entered this issue into their CAP as IR 680626 and IR 622574.

As part of their immediate corrective actions at that time, the licensee instituted administrative controls to provide an adequate quench volume for the RHUT and initiated an action to perform an analysis to investigate the magnitude of the potential water hammer loads on the RHUT inlet piping.

As part of their long-term corrective actions, the licensee generated an action to determine how to resolve the RHUT issues with agreement from Braidwood Station.

The agreement was reached with Braidwood in March 2008 and a revised corrective action was generated to track the final resolution of the issue. The revised corrective action included the performance of a water hammer analysis; and a RHUT piping and accident analysis, including an offsite dose analysis. Funding for these evaluations was approved for 2009, and the revised corrective action had an initial due date of December 2009.

In November 2009, the water hammer analysis was received from the vendor for owner review and acceptance. The RHUT pressure analysis was completed by the vendor and approved by the licensee in February 2010. However, the licensee decided to have a third party review the water hammer analysis before the result could be used for the piping analysis. In addition, the offsite dose analysis needed to be re-performed due to a non-qualified vendor being used and the inability of the licensee to qualify the vendors work. Contracts for all these analyses were issued between April and June 2011, and were scheduled to be completed by December 2011. At the end of this inspection, the licensee had not completed the actions to address the original NCV issued on November 12, 2008.

As documented in NRC Inspection Report 05000454/455/2009004, dated November 5, 2009, NCV 05000454/455/2009004-02 was issued when licensee personnel failed to seismically support and protect the emergency diesel generator (EDG) Diesel Oil Storage Tank (DOST) vent lines from tornado generated missiles.

This issue was initially identified by the NRC in February 2009. The licensee entered this issue into their CAP as IR 877430. As part of their immediate corrective actions at that time, the licensee performed an operability determination and concluded that even with the vent lines significantly degraded (crimped) or in the event that a seismic event caused the lines to fail completely, sufficient air would enter the DOSTs to replace the approximately one cubic foot per minute of fuel required to support EDG operation. As part of their long-term corrective actions, the licensee planned to formalize design basis documentation to justify the existing condition.

In August 2009, the licensee determined that the existing condition could not be justified and a physical modification was needed to restore regulatory compliance. In March 2010, the licensee determined that a vacuum breaker would be installed to resolve the issue. Due to other emergent issues and the complexity of the vacuum breaker modification and supporting analyses, the due date for resolving this issue was extended twice to December 2010. In December 2010, the licensee determined that the maximum allowable external pressure that the DOST could withstand was needed to design the vacuum breaker. An external vendor was contracted to calculate this maximum allowable external pressure; however, funding was not available until 2011. In May 2011, the licensee received the draft vendor analysis for the maximum allowable external pressure of the DOST. These results invalidated the licensees original plans to install a vacuum breaker.

In July 2011, the licensee concluded that a new modification was needed to resolve the issue. At the end of this inspection, the licensee was in the process of evaluating whether to re-route the vent line or to install a vacuum breaker and loop seal combination. This action had a due date of April 2012 with the actual modification installation not expected to be completed before the end of 2012.

Analysis:

The inspectors determined that the licensees failure to correct, in a timely manner, design issues identified in NRC Inspection Report 05000454/455/2008009, dated November 12, 2008, associated with NCV 05000454/455/2008009-02, and NRC Inspection Report 05000454/455/2009004, dated November 5, 2009, associated with NCV 05000454/455/2009004-02, was a performance deficiency that warranted a significance determination.

The issue was determined to be more than minor in accordance with IMC 0612, Appendix B, Issue Disposition Screening, because it was associated with the Mitigating Systems Cornerstone attribute of Equipment Performance and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, the RHUT was designed to support operation of the RHR system and the DOST vent line was designed to support operation of the EDGs; both of which were adversely affected by the issues identified and discussed above. The inspectors determined the finding could be evaluated using the SDP in accordance with IMC 0609, Significance Determination Process, Attachment 4, Phase I - Initial Screening and Characterization of Findings, Table 4a for the Mitigating Systems Cornerstone and answered No to all the Mitigating Systems Cornerstone questions. Specifically, the issue did not result in the actual loss of the operability or functionality of a safety system.

Therefore, the finding screened as having very low safety significance (Green).

This finding had a cross-cutting aspect in the Resources component of the Human Performance cross-cutting area (H.2(a)) because the licensee failed to maintain long-term plant safety by the minimization of long-standing equipment issues.

Enforcement:

10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, requires, in part, that measures shall be established to ensure that conditions adverse to quality are promptly identified and corrected.

Contrary to the above, as of September 2, 2011, the licensee failed to promptly correct two conditions adverse to quality as previously described in NCV 05000454/455/2008009-02 and NCV 05000454/455/2009004-02. Specifically, the design control deficiencies related to these issues had not been corrected since the NCVs were initially issued in November 2008 and November 2009, respectively.

Because this violation was of very low safety significance and because it was entered into the licensees CAP as IR 1269928, this violation is being treated as a NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy.

(NCV 05000454/2011008-01; 05000455/2011008-01: Untimely Corrective Actions for Previously Identified Non-Cited Violations)

.2 Assessment of the Use of Operating Experience

a. Inspection Scope

The inspectors reviewed the licensees implementation of the Operating Experience (OPEX) program. Specifically, the inspectors reviewed the OPEX program implementing procedures, and completed evaluations of OPEX issues and events.

The inspectors determined whether the licensee was effectively integrating OPEX experience into the performance of daily activities, whether evaluations of issues were proper and conducted by qualified personnel, whether the licensees program was sufficient to prevent future occurrences of previous industry events, and whether the licensee effectively used the OPEX information in developing departmental assessments and facility audits. The inspectors also assessed if corrective actions, as a result of OPEX experience, were identified and implemented in an effective and timely manner.

b. Assessment In general, OPEX was effectively used at the station. The inspectors observed that OPEX was discussed as part of the daily station and pre-job briefings. Industry OPEX was effectively disseminated across plant departments and no issues were identified during the inspectors review of licensee OPEX evaluations. During interviews, several licensee personnel commented favorably on the use of OPEX in their daily activities.

c. Findings

Failure to Initiate Issue Reports

Introduction:

The inspectors identified a Green finding and an associated NCV of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, when during the review of OPEX, licensee personnel failed to initiate IRs in accordance with licensee procedures to ensure that immediate actions, operability determinations, and reportability concerns were addressed by shift management within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

Description:

The inspectors reviewed OPEX 1173590, Part 21 ENS 46545 ABB Potential Defect Overcurrent Relays, dated February 10, 2011, and determined that the OPEX evaluation was completed and approved on April 21, 2011, following issuance of the associated 10 CFR Part 21 Notification on January 14, 2011. The inspectors noted that the subject matter expert in the Byron procurement engineering staff completed the OPEX evaluation using Attachment 1 of the OPEX evaluation template, LS-AA-115-1003, Processing of Significance Level 3 OPEX Evaluations, Revision 1.

Block I, Event Summary, of the completed OPEX evaluation identified that the subject of the 10 CFR Part 21 Notification involved the seismic qualification of overcurrent relays installed in 4.16 kV and 6.9 kV switchgear at Byron and Braidwood Station.

Block II, Operability Concerns, specifically directed the OPEX evaluator to perform the following action:

Evaluate the component(s) to determine if similar deficiencies are present that could represent potential operability issues. Provide sufficient justification to support whether potential operability concerns may exist. If an operability concern is established, provide the associated IR number. IR # ___________

The inspectors noted that the OPEX evaluator had not identified a potential operability concern despite having identified in Block I that the relays identified in the 10 CFR Part 21 Notification were installed in the plant. Instead, the evaluator documented the following:

It is not possible to make an Operability Determination at this time. There is inadequate information from ABB and Westinghouse to determine the affect the de-rated seismic qualification test levels for the COM overcurrent protection relays has on Byron Station. Since we do not have definitive information available to perform a detailed technical evaluation at this time, there is no need to evaluate the potential impact on operability, i.e. this issue is not in operability space at this time. When technical data is available, operability will be addressed in accordance with the appropriate technical reviews and evaluation process.

Block III, Applicability to Fleet or Station, requested, in part, Based on your review, is the issue applicable to station ... components? Yes or No. The OPEX evaluator correctly determined, Yes, Byron Station has COM-5 and COM-11 overcurrent protection relays installed in the plant in the Reactor Coolant Pump (RCP) motor control circuits. However, the OPEX evaluator had not noted that the relays were safety-related and protected the containment electric cable penetrations for the RCPs from failing due to an overcurrent condition.

Block VI, Actions, noted that, An IR must be initiated for any/all conditions adverse to quality that were identified in this evaluation. The OPEX evaluator did not identify the potentially suspect seismic qualification of the safety-related relays as a condition adverse to quality (CAQ) and therefore, an IR was not initiated.

The inspectors reviewed the licensees procedures for evaluating 10 CFR Part 21 Notifications. The OPEX evaluation was completed in accordance with licensee procedure LS-AA-115, Operating Experience Program, Revision 17. Attachment 1 of this procedure classified 10 CFR Part 21 Reports as Significance Level 3 to be evaluated using Manual LS-AA-115-1003. The purpose of Manual LS-AA-115-1003 was, in part, to provide guidance on the process to effectively conduct an OPEX Evaluation for .. applicable Part 21 Notifications and other important OPEX.

Paragraph 1.3 of LS-AA-115 stated, in part, that This manual is training and reference material, not a procedure. Attachment 1 to LS-AA-115-1003 was an evaluation template that provided guidance for completing the OPEX evaluation. The inspectors noted that although Section 4.1.5 of Procedure LS-AA-115 required a determination of whether the OPEX had the potential to impact Reactor Safety, Industrial Safety, or Generation for Level 2 OPEX documents, this determination was not technically required for Level 3 OPEX documents.

The inspectors reviewed LS-BY-125, Corrective Action Program (CAP) Procedure, Revision 3, and noted that this procedure stated, in part, that The identification and initial screening of the undesirable conditions is performed in accordance with LS-AA-120, Issue Identification and Screening Process. The inspectors noted that Section 4.1.2 of LS-BY-125 required that an IR be initiated in accordance with LS-AA-120 at any time (e.g., during an investigation, review of a corrective action closure, review of a previous IR) a SCAQ or condition adverse to quality (CAQ) or any question of either current or past Operability/Reportability arises. Procedure LS-AA-120, Issue Identification and Screening Process, required that all nuclear personnel and contractors identify any conditions that could have an undesirable effect on the performance of equipment, personnel, or organizations; ensure immediate actions are taken to place the situation in a safe condition; verbally report to a supervisor or the control room; and properly document the issue. Operations shift management was also required by LS-AA-120 to ensure appropriate immediate actions were taken, including determining impact on operability and reportability, and that operations management should complete these reviews within the same shift, with the operability determination completed within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

On April 6, 2011, IR 1198414, West NSAL 03-07 Supplement 1 Concerning ABB 1E Relays, was initiated on the same issue as OPEX 1173590 as related to the seismic qualification of the ABB COM-5, -9, and -11 relays. The licensees immediate action was to generate the IR to determine any immediate potential operability impacts.

However, IR 1198414 did not identify that the deficient relays were installed in the plant, the equipment the relays protected, and what could happen if the relays failed.

Consequently, on April 7, 2011, the shift manager documented the following in IR 1198414:

No Specific equipment was identified in this IR to evaluate Operability/Reportability. Additional IRs need to be written for specific equipment affected and if Operability/Reportability is a concern. Shift review for Operability and Reportability complete.

IR 1198414 was then forwarded to the same OPEX evaluator that reviewed OPEX 1173590. With this new information, the evaluator closed OPEX 1173590 and evaluated the seismic qualifications through IR 1198414. The OPEX evaluation documented that the relays remained qualified for use in the plant. With respect to the shift managers remarks regarding new IRs being initiated if any specific equipment was affected, the OPEX evaluator concluded that no new IRs needed to be initiated since Engineering personnel at Byron and Braidwood had both reviewed their equipment records and confirmed that the relays were only installed in the RCP circuit breakers.

The inspectors noted that the OPEX issue was subsequently reviewed, approved, and closed on April 19, 2011, and that no IRs were initiated that communicated the relay issue to the Operations department for review. Therefore, an operability determination was not completed by the Operations staff.

When the inspectors discussed this issue with licensee personnel, two IRs were immediately initiated. The first, IR 1257458, NRC PI&R Issues Identified with IR 1198414, dated August 30, 2011, was intended to communicate the issue to Operations for an immediate operability determination. The shift manager concluded the relays were operable based on the additional information provided regarding the seismic qualifications and requested a full operability evaluation from the engineering staff. The second, IR 1257444, Clear Direction Is Not Provided in LS-AA-115-1003, dated August 30, 2011, identified that the guidance in LS-AA-115-1003 could be misinterpreted to permit an OPEX evaluator to perform an operability determination and that the procedure was unclear as to whether an IR should be generated as an immediate action if potentially defective components were installed in the plant.

Overall, the inspectors concluded that despite identifying that the 10 CFR Part 21 Notification was applicable to the plant, recognizing that potentially defective relays that were the subject of the 10 CFR Part 21 Notification were installed in the plant, and clear direction in at least two blocks of the OPEX evaluation template to generate IRs, licensee personnel mistakenly concluded that engineering staff had the sole authority to determine whether an operability concern or CAQ existed. The inspectors also noted that an Engineering department manager had reviewed and approved the conclusions in the operability evaluation on April 21, 2011. Consequently, no IRs identifying the installation of potentially defective relays in the plant had been initiated, and therefore no operability determinations were performed for the installed potentially defective relays by the Operations department shift manager (the only person authorized to make an operability and reportability determination) between February 10, 2011 and August 30, 2011.

On August 31, 2011, IR 1257920, 10 CFR Part 21 Notification of Deviation - ABB KF Relay Seismic Ratings, was initiated identifying another instance of not generating an IR for an immediate operability determination after the identification of possibly deficient components installed in the plant. In this case, the OPEX issue, which was received on July 27, 2011, was not entered into the licensees CAP for review until an extent of condition review for the previous two issues discussed above was identified.

Analysis:

The inspectors determined that the licensees failure to follow station procedures to generate IRs to identify potentially defective components installed in the plant and obtain an immediate operability determination from the shift manager was a performance deficiency warranting a significance evaluation.

The issue was determined to be more than minor in accordance with IMC 0612, Appendix B, Issue Disposition Screening, because the performance deficiency, if left uncorrected, would have the potential to lead to a more significant safety concern.

Specifically, the failure to initiate IRs to properly assess the operability of potentially affected equipment could result in the failure to identify inoperable plant equipment. The inspectors determined the finding could be evaluated using the SDP in accordance with IMC 0609, Significance Determination Process, Attachment 4, Phase I - Initial Screening and Characterization of Findings, Table 4a for the Mitigating Systems Cornerstone and answered No to all the Mitigating Systems Cornerstone questions.

Specifically, the issue did not result in the actual loss of the operability or functionality of a safety system. Therefore, the finding screened as having very low safety significance (Green). The licensee entered this issue in their CAP as IR 1257548 and completed the required shift manager review.

This finding had a cross-cutting aspect in the Operating Experience component of the Problem Identification and Resolution cross-cutting area (P.2(a)) because the licensees procedures and guidance for OPEX did not systematically collect, evaluate, and communicate to affected internal stakeholders, in a timely manner, relevant internal and external OPEX.

Enforcement:

10 CFR 50, Appendix B, Criteria V, Instructions, Procedures, and Drawings, requires, in part, that activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions, procedures, or drawings. Licensee procedure LS-AA-125, Corrective Action Program Procedure, Step 4.1.2 stated: If at any time (e.g., during an investigation, review of a CA closure, review of a previous CR), a SCAQ or CAQ or any question of either current or past Operability/Reportability arises, then initiate an Issue Report (IR) in accordance with LS-AA-120, Issue Identification and Screening Process.

Contrary to the above, licensee personnel failed to initiate IRs in accordance with LS-AA-125 following the receipt of OPEX 1173590, Part 21 ENS 46545 ABB Potential Defect Overcurrent Relays, dated February 10, 2011; IR 1198414, West NSAL 03-07 Supplement 1 Concerning ABB 1E Relays, dated April 6, 2011; and OPEX 10 CFR Part 21 Notification of Deviation - ABB KF Relay Seismic Ratings, dated July 27, 2011, to ensure that immediate actions, operability determination, and reportability concerns were addressed by shift management. Because this violation was of very low safety significance and because it was entered into the licensees CAP as IR 1257548, this violation is being treated as a NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy. (NCV 05000454/2011008-02; 0500455/2011008-02:

Failure to Initiate Issue Reports)

.3 Assessment of Self-Assessments and Audits

a. Inspection Scope

The inspectors reviewed selected focused area self-assessments (FASAs), check-in self assessments, root cause effectiveness reviews, and Nuclear Oversight (NOS) audits.

The inspectors evaluated whether these audits and self-assessments were effectively managed, adequately covered the subject areas, and properly captured identified issues in the CAP. In addition, the inspectors interviewed licensee personnel regarding the implementation of the audit and self-assessment programs.

b. Assessment The inspectors concluded that self-assessments and audits were typically accurate, thorough, and effective at identifying issues and enhancement opportunities at an appropriate threshold. The inspectors concluded that these audits and self-assessments were completed by personnel knowledgeable in the subject area. In many cases, these self-assessments and audits had identified numerous issues that were not previously recognized by the station. For example, NOS identified an issue in the control of transient combustible material, which led to a comprehensive review of the combustible material control program and generated a number of corrective actions.

c. Findings

No findings were identified.

.4 Assessment of Safety Conscious Work Environment

a. Inspection Scope

The inspectors interviewed selected Byron Station personnel to determine if there were any indications that licensee personnel were reluctant to raise safety concerns, both to their management and the NRC, due to fear of retaliation. In addition, the inspectors discussed the implementation of the Employee Concerns Program (ECP) with the ECP coordinators, and reviewed ECP activities to identify any emergent issues or potential trends. The inspectors also assessed the licensees Safety Conscious Work Environment (SCWE) through a review of ECP implementing procedures, discussions with ECP coordinators, interviews with personnel from various departments, and reviews of IRs. The licensees programs to publicize the CAP and ECP programs were also reviewed. The inspectors reviewed the licensees semi-annual safety culture survey to assess if there were any organizational issues or trends that could impact the licensees safety performance.

b. Assessment The inspectors did not identify any issues that suggested conditions were not conducive to the establishment and existence of a SCWE at Byron Station. Licensee staff was aware of and generally familiar with the CAP and other station processes, including the ECP, through which concerns could be raised. In addition, a review of the types of issues in the ECP indicated that site personnel were appropriately using the CAP and ECP to identify issues.

The staff also expressed a willingness to challenge actions or decisions that they believed were unsafe. In fact, several employees had stated that they had written IRs repeatedly for issues that were not corrected to their satisfaction. All employees interviewed noted that any safety issue could be freely communicated to supervision and safety significant issues were being corrected. Although some employees indicated a small degree of frustration related to low level items not being corrected in a timely manner, the inspectors determined that the timeliness of the planned corrective actions for the examples given were commensurate with their safety significance.

A number of employees stated that due to limited resources, they had to prioritize their work and work overtime, which resulted in a delay in the resolution of some of the less significant issues. This feedback aligned the inspectors observations in the assessment of the corrective action program as discussed above.

c. Findings

No findings were identified.

4OA6 Management Meetings

a.

Exit Meeting Summary

On September 7, 2011, the inspectors presented the inspection results to Mr. B. Adams, and other members of the licensee staff. The licensee acknowledged the issues presented. The inspectors confirmed that none of the potential report input discussed was considered proprietary.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

B. Adams, Plant Manager

B. Barton, Radiation Protection Manager

E. Blondin, Plant Engineering Senior Manager

D. Coltman, Operations Support Manager

D. Gudger, Regulatory Assurance Manager

S. Kerr, Work Management Director

B. Spahr, Maintenance Director

S. Swanson, Nuclear Oversight Manager

P. Woessner, Site Correction Action Program Manager

NRC

E. Duncan, Branch Chief

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

05000454/2011008-01; NCV Untimely Corrective Action for Previously Identified

05000455/2011008-01 Non-Cited Violations (Section 4OA2.1.b.3.i)

05000454/2011008-02; NCV Failure to Initiate Issue Reports

05000455/2011008-02 (Section 4OA2.2.c)

Closed

05000454/2011008-01; NCV Untimely Corrective Action for Previously Identified

05000455/2011008-01 Non-Cited Violations (Section 4OA2.1.b.3.i)

05000454/2011008-02; NCV Failure to Initiate Issue Reports

05000455/2011008-02 (Section 4OA2.2.c)

Attachment