IR 05000456/2012007

IR 05000456-12-007, 05000457-12-007, 06/11/2012 06/29/2012, Braidwood Station, Units 1 and 2, Identification and Resolution of Problems

ML12222A117
Person / Time
Site:	Braidwood
Issue date:	08/08/2012
From:	Eric Duncan Region 3 Branch 3
To:	Pacilio J Exelon Generation Co, Exelon Nuclear
References
IR-12-007
Download: ML12222A117 (42)

Text

ust 8, 2012

SUBJECT:

BRAIDWOOD STATION, UNIT 1 & 2, NRC PROBLEM IDENTIFICATION AND RESOLUTION INSPECTION REPORT 05000456/2012007; 05000457/2012007

Dear Mr. Pacilio:

On June 29, 2012, the U.S. Nuclear Regulatory Commission (NRC) completed a Problem Identification and Resolution (PI&R) inspection at your Braidwood Station. The enclosed inspection report documents the inspection results, which were discussed at an exit meeting on June 29, 2012, with Mr. J. Bashor and other members of your staff.

The inspection examined activities conducted under your license as they relate to safety and compliance with the Commissions 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, overall, the corrective action program (CAP) at Braidwood Station was adequate in identifying, evaluating and correcting issues with various degrees of effectiveness. The licensee had a low threshold for identifying issues and entering them into the CAP. Issues entered in the CAP were prioritized and evaluated based on plant risk and uncertainty. Corrective actions were generally implemented in a timely manner, commensurate with their 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, self-assessments, audits, and effectiveness reviews were found to be conducted at appropriate frequencies with sufficient depth 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 impediment to the establishment of a Safety Conscious Work Environment (SCWE) at Braidwood Station. Licensee 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.

Although implementation of the CAP was determined to be adequate, overall, based on the samples reviewed four findings of very low safety significance (Green) were identified during this inspection in the areas of Corrective Action Program Effectiveness and Operating Experience. Three of these four findings were also determined to involve a violation of NRC requirements. However, because of their very low safety significance and because the issues were entered into your CAP, 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, the team identified several issues that were either minor in nature and/or represented negative trends, warranting your attention. Examples include implementation of the operability determination process, CAP procedures not being followed, and the timeliness of corrective actions to address degraded fire barriers.

If you contest the subject or severity of an NCV, 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 Braidwood Station.

If you disagree with a cross-cutting aspect 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 Resident Inspector Office at the Braidwood Station.

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 NRCs Agencywide Documents Access and Management 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. 50-456 and 50-457 License Nos. NPF-72 and NPF-77

Enclosure:

Inspection Report No. 05000456/2012007 and 05000457/2012007 w/Attachment: Supplemental Information

REGION III==

Docket Nos: 50-456; 50-457 License Nos: NPF-72; NPF-77 Report Nos: 05000456/2012007; 05000457/2012007 Licensee: Exelon Generation Company, LLC Facility: Braidwood Station, Units 1 and 2 Location: Braidwood, IL Dates: June 11, 2012, through June 29, 2012 Team Leader: R. Ng, Project Engineer Inspectors: A. Garmoe, Resident Inspector D. Chyu, Reactor Engineer D. Szwarc, Reactor Inspector M. Perry, Resident Inspector, Illinois Emergency Management Agency Approved by: E. Duncan, Chief Branch 3 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

Inspection Report (IR) 05000456/2012007; 05000457/2012007; 06/11/2012 - 06/29/2012;

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

This inspection was performed by region-based inspectors, the Braidwood Resident Inspector, and the Braidwood Illinois Emergency Management Agency (IEMA) resident inspector. Four findings of very low safety significance (Green) were identified by the inspectors. Three of these findings were determined to involve Non-Cited Violations (NCVs) of NRC requirements. 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 Braidwood Station was adequate in identifying, evaluating and correcting issues with various degrees of effectiveness. The licensee had a low threshold for identifying issues and entering them into the CAP. Issues entered in the CAP were prioritized and evaluated based on plant risk and uncertainty. Corrective actions were generally implemented in a timely manner, commensurate with their 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 with sufficient depth 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 impediment to the establishment of a Safety Conscious Work Environment (SCWE) at Braidwood Station. Licensee 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.

Although implementation of the CAP was determined to be adequate, overall, four findings of very low safety significance (Green) were identified by the inspectors. Three of these findings were also determined to involve NCVs of NRC requirements. Two Green findings concerned the licensees failure to implement corrective actions to address previously identified NRC violations. The third Green finding was related to the failure to initiate Issue Reports (IRs) as required by licensee procedures to address potential equipment operability issues. The last Green finding was related to the failure to implement corrective actions to prevent recurrence.

In addition, the team identified several issues that were either minor in nature and/or represented negative trends. Examples include implementation of the operability determination process, CAP procedures not being followed, and the timeliness of corrective actions to address degraded fire barriers.

NRC-Identified

and Self-Revealed Findings

Cornerstone: Initiating Events, Mitigating Systems

• Green: A finding of very low safety significance (Green) and an associated NCV of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, was identified by the inspectors when a non-conforming condition previously identified by the NRC was not corrected. Specifically, the licensee did not plan or perform corrective actions for a non-conforming condition where lead blankets were placed on various safety-related pipes without meeting American Society of Mechanical Engineers (ASME)

Code requirements. The licensee entered this issue into the CAP as IR 1383554 and planned to perform the required analyses.

The inspectors determined that the failure to correct a non-conforming condition was more than minor because it was associated with the Design Control attribute of the Mitigating Systems cornerstone 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 licensee failed to ensure compliance with American Institute of Steel Construction (AISC) and ASME Boiler and Pressure Vessel Code Section III requirements to ensure the piping and pipe supports would maintain their structural integrity when subjected to design basis loads. The finding was determined to be of very low safety significance (Green) because it was a design or qualification deficiency confirmed not to result in loss of operability or functionality. This finding had a cross-cutting aspect in the Decision-Making component of the Human Performance cross-cutting area H.1(b) because licensee personnel failed to verify the assumption that NCIG-5 could be used in lieu of meeting the design bases ASME Code requirement.

(Section 4OA2.1.b.2.ii)

• Green: A finding of very low safety significance (Green) and an associated NCV of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified by the inspectors when licensee personnel failed to adhere to Surveillance Procedure BwHS 4002-012, Revision 9, AF [Auxiliary Feedwater] Nickel Cadmium Battery Surveillance. Specifically, the licensee failed to identify open spaces between the wooden shim blocks and the end of the battery rack for the diesel-driven AF pump batteries. The licensee entered this issue into the CAP as IR 1379674 and planned to replace the shim blocks.

The inspectors determined that the failure to follow the surveillance procedure was more than minor because it was associated with the Equipment Performance attribute of the Mitigating Systems Cornerstone 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 licensee failed to ensure that batteries were restrained from sliding along the rack to avoid over-stressing the end or base of the racks as specified in the seismic qualification document. The finding was determined to be of very low safety significance (Green) because it was a design or qualification deficiency confirmed not to result in a loss of operability or functionality. This finding had a cross-cutting aspect in the Work Practices component of the Human Performance cross-cutting area H.4(b) because the licensee failed to effectively communicate the expectation and the bases regarding the acceptance criteria of the surveillance procedure. (Section 4OA2.1.b.3.ii)

• Green: A finding of very low safety significance (Green) was identified by the inspectors when licensee personnel failed to follow procedure LS-AA-125-1001,

Root Cause Analysis Manual, Attachment 12, in the implementation of corrective actions to prevent recurrence. Specifically, actions taken in response to the Unit 1 reactor trip on August 16, 2010, did not meet the criteria in procedure LS-AA-125-1001, Attachment 12, CAPR Attributes, for being timely, effective, and long-lasting (i.e. not temporary). The licensee entered this issue into the CAP as IR 1395327.

The inspectors determined the failure to follow procedure LS-AA-125-1001 was more than minor because it could be reasonably viewed as a precursor to a significant event and, if left uncorrected, had the potential to lead to a more significant safety concern. Specifically, the licensee continued to rely on administrative controls, temporary catch containments, and transferring water slowly to prevent water overflow events rather than through a permanent modification to the standpipes. As a result, the potential for water overflow events, while reduced, would not prevent recurrence. The inspectors determined that the finding was of very low safety significance (Green) because it did not contribute to both the likelihood of a reactor trip and the likelihood that mitigation equipment or functions would not be available.

This finding had a cross-cutting aspect in the Corrective Action Program component of the Problem Identification and Resolution cross-cutting area P.1(d) since the licensee did not take timely and appropriate corrective actions to prevent recurrence in response to the August 16, 2010, Unit 1 reactor trip. (Section 4OA2.1.b.3.ii)

• Green: The inspectors identified a finding of very low safety significance (Green)and an associated NCV of 10 CFR Part 50, Appendix B, Criterion V, Instructions,

Procedures, and Drawings, when licensee personnel failed to initiate IRs in accordance with the CAP procedure. Specifically, the licensee failed to initiate an IR and perform an operability determination during a 10 CFR Part 21 Notification evaluation. The licensee entered this issue into their CAP as IR 1378432 and determined that there were no operability or reportability issues.

The inspectors determined that the finding was more than minor because the finding, if left uncorrected, could become a more significant safety concern. Specifically, if operations staff was not made aware of potentially degraded safety-related components, they might not perform an operability determination and continue operating the plant with the degraded components. The finding was of very low safety significance (Green) because the finding did not result in a loss of operability or functionality of equipment. 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 licensee did not systematically evaluate and communicate relevant operating experience to affected internal stakeholders.

(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 Braidwood 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 September of 2010. 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 (RCEs),apparent cause evaluations (ACEs), 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 125 Volt Direct Current (Vdc) system to review in detail since the 125 Vdc system was a risk-significant Maintenance Rule 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 125 Vdc system engineer, reviewed numerous 125 Vdc system related IRs, and reviewed system health reports associated with the 125 Vdc system. A 5-year review of 125 Vdc 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 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.

b.

Assessment

(1) Identification of Issues Based on the results of the inspection, the inspectors concluded that, in general, the station was adequate in identifying issues at a low threshold and entering them into the CAP. The inspectors determined that the station was appropriately screening issues from both NRC and industry 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. These deficiencies were entered into the CAP for resolution.

However, the inspectors noted several occasions where there has been a delay in writing IRs in response to resident inspectors questions. Some recent examples include questions on available margin with the depth of the ultimate heat sink, High Energy Line Break (HELB) induced differential pressures across doors, whether potentially pertinent information was presented at a Plant Onsite Review Committee meeting, and whether a Title 10 Code of Federal Regulation (CFR) 50.59 evaluation was completed properly.

Additionally, the licensee self-identified in IR 1384767 that IRs were sometimes not written until after licensee personnel had analyzed and/or resolved the problem.

Although the inspectors considered these delays minor procedural violations, they could potentially affect the effectiveness of the CAP since issues might not receive appropriate attention if they are not identified and documented in a timely manner. The licensee acknowledged this weakness and generated IR 1381936 to address the issue.

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:

Adverse Trend in Operability Determination Process The inspectors noted an apparent adverse trend in the quality of operability evaluations completed by site personnel based on a review of prior NRC findings and licensee IRs.

The following findings and NCVs were noted to involve inadequacies in operability evaluations:

o NCV 05000457/2011004-05, Asiatic Clams Identified in the SX [Essential Service Water] System Supply to the AF [Auxiliary Feedwater] System o FIN [Finding] 05000456/457/2011005-04, Operability Evaluation Not Performed in Accordance with Station Standards o FIN 05000456/457/2011012-02, Failure to Adequately Document and Justify Continued Operability of the Auxiliary Feedwater System The inspectors also noted numerous recent IRs that were generated based on NRC comments and concerns on several Operability Evaluations, including:

o IR 1193357 - AF Void OpEval [Operability Evaluation] 11-03 o IR 1199223 - HELB [High Energy Line Break] Past Operability Review o IR 1202772 - AFW [Auxiliary Feedwater] Pump Suction Piping o IR 1231877 - Green Finding on AFW Voids Operability Justification o IR 1242942 - NRC Comments on OpEval 11-06 o IR 1276888 - Effect of HELB on Rx [Reactor] Trip Breakers o IR 1279543 - HELB Single Failure o IR 1291688 - Green Finding on AF Shells [incorrect operability conclusion]

o IR 1291695 - Failure to Analyze SX to AF configuration [incorrect operability conclusion]

o IR 1299906 - Summary of NRC HELB OpEval Comments & Missed 50.73 o IR 1326152 - HELB OpEval Green Finding o IR 1366538 - Lack of CST [Condensate Storage Tank] OpEval (from 2010 PI&R)o IR 1368315 - Questions on HELB Gothic Analysis o IR 1372307 - 1A MSIV [Main Steam Isolation Valve] Remote Shutdown Panel Not Considered in Op Determination o IR 1378432 - Braidwood Not Notified of Byron OpEval o IR 1382574 - NRC Questions Related to HELB (OpEval 11-06 and 12-04)

Based on the information reviewed, the inspectors questioned whether the licensee had identified an adverse trend regarding operability evaluation quality and whether the licensee had performed any type of common cause analysis for this issue. The licensee indicated that no such actions had been completed and subsequently initiated IR 1384115, NRC Idd: Adverse Trend in Operability Evaluation Quality, to evaluate the inspectors observations.

In addition to the quality of operability evaluations, the inspectors noted weaknesses in the licensees operability determination procedure, OP-AA-108-115, Operability Determinations. Specifically, Inspection Manual Chapter (IMC) Part 9900, Operability Determinations and Functionality Assessments for Resolution of Degraded or Nonconforming Conditions Adverse to Quality or Safety, stated the following:

o Circumstance Warranting Operability Determinations.

Licensees should enter the operability determination process upon discovering any of the following circumstance when the operability of any systems, structures, and components described in the TS [Technical Specifications] is called into question:

a) Degraded conditions; b) Nonconforming conditions; and c) Discovery of an unanalyzed condition.

However, procedure OP-AA-108-115 did not include discovery of an unanalyzed condition as a condition warranting an operability evaluation. The inspectors also noted that, as opposed to a three-working-day requirement to complete new operability evaluations, there was no defined time limit for revising an operability evaluation, even if new information potentially challenged an existing operability determination conclusion.

The inspectors also noted an example in which the licensee did not thoroughly evaluate the aggregate impact of two operability evaluations that could have affected one another (Operability Evaluations12-001 and 12-002) because one of the conditions was considered outside of the current licensing basis. The inspectors did not identify any guidance addressing this type of situation in the licensees procedures. Based on prior inspection observations, as documented in Section 4OA5.5.b of Byron Inspection Report 05000454/2012008; 05000455/2012008, the licensee had previously initiated IR 1325902 for the issue. Assignment 2 of that IR was closed to a corporate action to revise procedure OP-AA-108-115. However, the corporate action to complete the procedure revision was not referenced anywhere in IR 1325902 such that it could be tracked.

Although the individual concerns with the quality of the operability evaluation were considered minor, the trend indicated a potential weakness in the process that had a negative impact on equipment operability determinations.

(2) Prioritization and Evaluation of Issues Based on the results of the inspection, the inspectors concluded that the station was marginally effective at prioritizing and evaluating issues commensurate with the safety significance of the identified issue, including an appropriate consideration of risk.

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 reviewed Maintenance Rule action plans and issue reports associated with the 125 Vdc system because, in part, a significant number of identified deficiencies associated with this system had been identified in the last 5 years. The licensee developed action plans to resolve these deficiencies and appropriately adjusted the actions when new issues were discovered.

The inspectors determined that the licensee usually evaluated equipment functionality requirements adequately after a degraded or non-conforming condition was identified.

However, in many instances, NRC involvement was required to ensure appropriate questions were researched, particularly as associated with operability determinations.

Many issue evaluations lacked sufficient rigor to define the issues thoroughly and appropriately resolve them. (See Observations in Section 4OA2.1.b.1.i above and Findings in Section 4OA2.1.b.2.ii below). In addition, the inspectors identified a number of weaknesses related to the prioritization and evaluation of issues as described below:

i) Observations:

CAP Procedure Not Being Followed The inspectors observed several examples where the significance level or assignment type associated with IRs was not in accordance with procedures LS-AA-120, Issue Identification and Screening Process, or LS-AA-125, Corrective Action Program Procedure. Specific examples identified by the inspectors included the following:

o IR 1218755 included an assignment to address a contributing cause of an inoperable AF system due to Asiatic clam shells in the inlet piping. The assignment was closed without addressing the cause.

o IR 1295149 was assigned a Significance Level 5, an enhancement, but should have been assigned a Significance Level 4, as a valid calibration was required to perform a surveillance procedure; o IR 1364132 was assigned a Significance Level 4, but should have been assigned a Significance Level 3 due to the resulting online risk change; o IR 1257969 had an assignment improperly coded as an Action Tracking Item (ACIT), an improvement item, to address a non-conforming condition; o IR 1126534 was initiated to address an NRC-issued NCV, but had only ACIT assignments; o IR 1349305 was generated for a small fire in the turbine building, however, an ACIT assignment was used to evaluate how to clean greasy dust and debris, which was identified as a contributing cause of the fire; o COMP assignments were not used by the site to track temporary compensatory actions for degraded or non-conforming conditions. Instead, compensatory actions were typically tracked as corrective actions, which was not in accordance with the procedure and procedure definitions; and o Operability Determination procedure OP-AA-108-115 allowed compensatory measures to be tracked using an ACIT assignment, which was contrary to the significance of the actions since ACITs were not tracked in CAP and could be closed by the department without senior management review.

The inspectors concluded that the site was not always following established procedural guidance regarding the significance level of IRs and the associated assignment types.

The inspectors considered many of these examples to represent a failure to comply with 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings.

However, these violations were of minor significance and in accordance with the NRCs Enforcement Policy were not subject to enforcement action.

ii) Findings:

Non-Conforming Piping Condition Not Corrected

Introduction:

The inspectors identified a finding of very low safety significance (Green)and an associated NCV of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, when a non-conforming condition, previously identified by the NRC in September 2011, was not properly corrected. Specifically, the licensee did not plan or perform corrective actions for a non-conforming condition in which lead blankets were placed on various safety-related pipes without ensuring American Society of Mechanical Engineers (ASME) Code requirements were met.

Description:

In September 2011, the NRC identified in Inspection Report 05000456/2011008; 05000457/2011008 that permanent lead shielding was added to safety-related piping and pipe supports 1SI06 (Safety Injection) and 1CV18 (Chemical Volume and Control System) without demonstrating compliance with the American Institute of Steel Construction (AISC) and ASME Class III Boiler and Pressure Vessel Code. Instead of meeting the associated AISC and ASME Code requirements, the licensee inappropriately used Electric Power Research Institute (EPRI) document NCIG-05, Guideline for Piping Reconciliation, to evaluate the permanent modifications to the piping. This issue was documented as NCV 05000456/2011008-02.

The licensee documented their initial response to this NCV in IR 1269227, NRC MOD/50.59 Inspection - Use of NCIG-05 For Lead Shielding. In that IR, the licensee concluded that the intent of the NRC endorsement of NCIG-05 was not for installations, but only for reconciliations. In response to the NCV, the licensee revised procedure CC-AA-309-1011, General Station Piping Analysis, to prevent future use of NCIG-05 method for permanent modifications. The licensee also placed a hold on all pending modifications that were based on NCIG-05 until the associated calculations were appropriately revised to address the piping changes.

However, the licensee stated in IR 1269227 that although the use of NCIG-05 for this application was not in accordance with CC-AA-309-1011, the results and conclusions of the design evaluation using these guidelines remained valid and design margins for these subsystems remained acceptable. The licensee noted that in cases where the piping calculations supporting modifications relied upon the tolerances provided within NCIG-05, there was no value in revising the calculations. The licensee mistakenly reasoned that while the modifications were installed without verifying that the Code requirements were met, it was now acceptable to use NCIG-05 as a basis to accept the deviations from the original approved ASME Class III piping analysis. Thus, ASME Code calculations for subsystems 1CV18 and 1SI06 were not revised to restore the non-conforming condition. The licensee entered this issue into the CAP as IR 1383554 and planned to perform the required analyses.

Analysis:

The inspectors determined that the failure to properly address a non-conforming condition associated with the installation of permanent lead shielding on 1SI06 and 1CV18 was a performance deficiency. The performance deficiency was determined to be more than minor because it was associated with the Design Control attribute of the Mitigating Systems Cornerstone 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 licensee failed to ensure compliance with AISC and ASME Boiler and Pressure Vessel Code Section III requirements to ensure the piping and pipe supports would maintain their structural integrity when subjected to design basis loads.

The inspectors determined that the finding could be evaluated using the SDP in accordance with IMC 0609, Attachment 4, Phase 1- Initial Screening and Characterization of Findings. Using Table 2, the inspectors determined that the issues affected the Decay Heat Removal function of the Mitigating Systems Cornerstone.

Based on the Mitigating Systems Cornerstone questions in Table 4a, the inspectors determined that the finding was a design or qualification deficiency confirmed not to result in loss of operability or functionality. Therefore, the finding was determined to be of very low safety significance (Green).

The inspectors determined that this finding had a cross-cutting aspect in the Decision-Making component of the Human Performance cross-cutting area H.1(b)

because licensee personnel mistakenly concluded that NCIG-5 could be used in lieu of satisfying design bases AISC and ASME Code requirements.

Enforcement:

Title 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, requires, in part, that measures shall be established to assure that conditions adverse to quality, such as failures, malfunctions, and non-conformances are promptly identified and corrected. Contrary to the above, as of June 29, 2012, the licensee failed to correct a non-conformance associated with lead blankets on safety-related piping, which is a condition adverse to quality. Specifically, the licensee did not evaluate the modified piping as required by ASME Boiler and Pressure Vessel Code Section III in order to correct a non-conforming condition identified by the NRC in September of 2011.

Because this violation was of very low safety significance and it was entered into the licensees CAP as IR 1383554, it is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy. (NCV 05000456/2012007-01; Non-Conforming Piping Condition Not Corrected)

(3) Effectiveness of Corrective Action Based on the results of the inspection, the inspectors concluded that the licensee was adequate in implementing corrective actions in a timely manner to address identified deficiencies, commensurate with their safety significance, including an appropriate consideration of risk. 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, in many instances, the effectiveness of the corrective actions was impacted by the lack of vigor in evaluating issues, as described in the previous section. This had resulted, in some cases, in rework and NRC enforcement actions.

The inspectors also identified that there were over 3600 open IRs at the time of the inspection. More than 12 percent of these open IRs were greater than 1 year old. The inspectors also identified that the number of outstanding corrective actions was relatively large with three IRs having corrective actions that were over 1700 days old. The inspectors reviewed a sample of these 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. Other outstanding actions were associated with License Amendment Requests or modifications to the plant. The inspectors verified that the sampled IRs were evaluated and actions assigned appropriately. The inspectors concluded that most of these corrective actions were considered timely due to the relatively long lead time required for modification or for NRC approval. The inspectors regarded this aging IR issue as an improvement opportunity since the outstanding actions, even when some were considered enhancements, could potentially affect the licensees focus on more important safety issues and complicate resource utilization.

i) Observations:

Untimely Implementation of Corrective Action to Prevent Recurrence The inspectors identified one example of untimely implementation of corrective actions to prevent recurrence (CAPR). This subject CAPR was to apply human factors to the design of several control room annunciator windows to alert operators of the need to perform immediate actions to address a TS Limiting Condition for Operation (LCO).

These actions were being performed to address a previous failure to perform actions required by TSs for an inoperable Boron Dilution Prevention System as described in IR 1101873. The CAPR was approved by the MRC in 2010, but the action was still being evaluated at the time of this inspection. The inspectors determined that because the issue did not involve a safety-related system and the other corrective actions, such as procedure revisions, were in place to prevent recurrence of the event, the issue was not subject to NRC enforcement action.

Degraded Fire Barriers The inspectors followed up on the licensees corrective actions to previously issued NRC findings and violations. One of the previously issued violations was NCV 05000457/2010005-01, Degraded Fire Seal Between Two Fire Zones. This issue was initially documented in IR 1126534 and 1126594. The inspectors noted that the issue of degraded fire seals actually dated back to performance of a fire-rated barriers inspection in 1999. At that time, the fire seals had surface degradation that did not adversely affect seal operability, but could in the future if not repaired. Several work requests were opened to repair the seals, but none of the work was performed.

In August 2007, the licensee identified a partially missing fire seal and initiated IR 659293. They performed an extent of condition assessment, which was documented in IR 666968. The licensee concluded that the seals were intact and operable, but with surface degradation. It was also noted at the time that the work requests generated in 1999 had not been performed. The licensee subsequently closed those work requests to new Work Orders (WOs). In October 2010, NRC inspectors identified degraded fire seal conditions that were the subject of IR 1126534 and NCV 05000457/2010005-01. At that time, the WOs created in 2007 had not been completed.

During this PI&R inspection, the inspectors noted that many of the WOs created in 2007 had still not been completed, though some fire seals had been repaired. The remaining WOs were scheduled at various times in 2012 and 2013.

The inspectors determined that this issue represented poor performance in terms of CAP timeliness and effectiveness. While the fire seals were intact and operable, with the exception of the issue documented in NCV 05000457/2010005-01, engineering stated in numerous IRs that the seals would continue to degrade to the point of inoperability if they were not repaired in a timely manner. The inspectors considered this to be an example of untimely correction of a non-conforming condition. The inspectors considered many of these examples to represent a failure to comply with 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings. However, because the seals were intact and operable throughout the time period in question, with the exception of the fire seal described in NCV 2010005-01, these issues constituted violations of minor significance that were not subject to enforcement action in accordance with the NRCs Enforcement Policy. This issue was entered into the licensees CAP as IR 1383304.

ii) Findings:

Surveillance Procedure Not Followed

Introduction:

The inspectors identified a finding of very low safety significance (Green)and an associated NCV of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, when licensee personnel failed to adhere to Surveillance Procedure BwHS 4002-012, Revision 9, AF Nickel Cadmium Battery Surveillance.

Specifically, the licensee failed to identify open spaces between the wooden shim blocks and the end of the battery rack for the Unit 1 and Unit 2 diesel-driven AF pump batteries, which represented a seismic concern.

Description:

On May 6, 2010, the NRC issued Inspection Report 05000456/20100007; 05000457/2010007 following a Component Design Bases Inspection. That inspection identified that the licensee failed to provide adequate justification as to why the existing wooden shim blocks would seismically qualify the mounting of the diesel-driven AF pump batteries in a postulated seismic event, given several 0.25 inch gaps that were identified. As a corrective action to this NCV, the licensee revised the surveillance procedure to add a note fully explaining the requirements for the shims.

While performing a walkdown of corrective actions from the NCV on June 19, 2012, the inspectors identified that there were wooden shim blocks that were fitting very loosely at the end of battery racks 1/2AF01EA-B and 1/2AF01B-B. Per surveillance procedure, BwHS 4002-012, the acceptance criterion was to fill the open space between the wooden spacer blocks and to have minimum or no free play so that the blocks could not be easily knocked loose at the end of the battery racks. The shims were required to be the same height as the existing wooden shim blocks and all shims were required to fit snugly (but not force fit). The inspectors reviewed the completed surveillance for June 2012 and determined that the surveillance was documented as satisfactory, but should not have been given the existing shim conditions. The licensee entered the issue into the CAP as IR 1379674 and planned to replace the shim blocks.

Analysis:

The inspectors determined that licensees failure to follow Surveillance Procedure BwHS 4002-012, Revision 9, AF Nickel Cadmium Battery Surveillance, was a performance deficiency. The performance deficiency was determined to be more than minor because it was associated with the Equipment Performance attribute of the Mitigating Systems cornerstone, and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the licensee failed to ensure that batteries were constrained from sliding along the rack to avoid over-stressing the end or base of the racks as specified in the seismic qualification document.

The inspectors determined that the finding could be evaluated using the SDP in accordance with IMC 0609, Attachment 4, Phase 1 - Initial Screening and Characterization of Findings. Using Table 2, the inspectors determined the issue affected the Secondary Heat Removal Function of the Mitigating Systems Cornerstone.

Using the Mitigating Systems cornerstone questions in Table 4a, the inspectors determined that the finding was a design or qualification deficiency confirmed not to result in loss of operability or functionality. Therefore, the finding was determined to be of very low safety significance (Green).

The inspectors determined that this finding had a cross-cutting aspect in the Work Practices component of the Human Performance cross-cutting area H.4(b) because the licensee failed to effectively communicate expectations regarding the acceptance criteria of the surveillance procedure.

Enforcement:

Title 10 CFR Part 50, Appendix B, Criterion 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, procedure, or drawings. Braidwood procedure BwHS 4002-012, Revision 9, AF Nickel Cadmium Battery Surveillance, prescribes the safety-related battery surveillance, which is an activity affecting quality. The acceptance criterion in Step 6.4 of that procedure states, Ensure wooden spacer blocks are installed tightly in the battery rack. Contrary to the above, the licensee failed to accomplish an activity affecting quality. Specifically, the licensee failed to identify gaps in AF pump battery racks between the wooden shim blocks and the end frames and had shims that did not meet the conditions specified in the procedure note that applies to Step 6.4.

Because this violation was of very low safety significance and it was entered into the licensees CAP as IR 1383554, it is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy. (NCV 05000456/2012007-02; Surveillance Procedure Not Followed)

Untimely Completion of a Corrective Action to Prevent Recurrence

Introduction:

The inspectors identified a finding of very low safety significance (Green)when licensee personnel failed to follow procedure LS-AA-125-1001, Root Cause Analysis Manual, Attachment 12, CAPR Attributes, in the implementation of CAPRs.

Specifically, actions taken to date in response to the Unit 1 reactor trip on August 16, 2010, did not meet the criteria in procedure LS-AA-125-1001, Attachment 12, for being timely, effective, and long-lasting (i.e. not temporary).

Description:

On August 16, 2010, the site experienced reactor trips of both units within approximately 15 minutes for unrelated reasons. The details of the event are documented in NRC Inspection Reports 05000456/2010004; 05000457/2010004 and 05000456/2010010; 05000457/2010010. Following the Unit 2 reactor trip, condenser hotwell level rose to the point where a hotwell reject occurred. This transferred water into a piping header that communicates with the CST, AF system, and several other plant water systems. The piping header contained a stand pipe that was open-ended onto the turbine deck. When the hotwell reject occurred, approximately 12,000 gallons of water spilled from the stand pipe onto the turbine deck. This water dripped into a Unit 1 motor control center on a lower elevation and caused two Unit 1 circulating water pumps to trip. As a result of reduced condenser vacuum, the Unit 1 turbine and reactor tripped as designed.

The licensee performed a root cause evaluation of the Unit 1 reactor trip and identified two root causes. Root Cause #1 was determined to be an inadequate design of the AF stand pipes. The assigned CAPR for root cause #1 was to install a design feature on the AF stand pipe which prevents water spill events. The licensees root cause evaluation also stated that two condensate system valves, 1/2CD142 and 1/2CD145, should be closed as an interim correction action for the respective units. The Engineering Change evaluation for changing the operating configuration of these two valves was approved on August 19, 2010 and procedures were revised to implement this action. The revised procedures directed operators to position a temporary catch containment at the discharge of the standpipes during a hotwell reject due to high hotwell level or the transfer of water between the hotwells and CSTs for temperature control.

On October 17, 2010, during a Unit 1 refueling outage, Operations personnel were refilling portions of the condensate system when it was discovered that a substantial amount of water was overflowing onto the turbine deck from the Unit 1 AF stand pipe.

The overflow was terminated when the CSTs for each unit were cross-tied. The licensee performed a Prompt Investigation of the issue and determined the cause to be system design. Operations Standing Order 10-16 was created to control CST level at or below 91 percent, to provide guidance on filling systems with water slowly, and to station a watch at the stand pipes to identify overflow conditions. Even with closing the two condensate system valves, these actions might not prevent overflow for all system line-ups and operations.

The root cause evaluation for the August 16, 2010, Unit 1 reactor trip was completed on November 11, 2010. On June 14, 2011, the licensee documented in CAP that the installation of a vacuum breaker valve on the Unit 1 and Unit 2 standpipes would prevent water overflow. The licensee approved the design change on January 26, 2012, for inclusion in the Unit 1 and Unit 2 refueling outages in October 2013 and May 2014, respectively.

On April 5, 2012, the licensee generated IR 1350723 to evaluate revising the root cause evaluation to remove the CAPR to install the modification on the AF standpipe. Instead, the licensee desired to credit the plant lineup changes and administrative controls previously implemented as the CAPR. As of the conclusion of the inspection period, the licensee had not completed the originally documented CAPR #1 and had also not completed their determination of whether to change the CAPR from a design modification to the existing actions.

The inspectors concluded that the actions taken to date, which were the closure of valves 1/2CD142 and 1/2CD145 and related procedure revisions, controlling CST level via Standing Order 10-16, and the use of temporary catch containments did not meet several of the CAPR attributes contained in licensee procedure LS-AA-125-1001, Root Cause Analysis Manual, Attachment 12. Specifically, these actions did not meet the attributes of being timely, effective, and long lasting (i.e. not temporary). The attribute of timeliness was not met because the licensee was continuing to evaluate what the appropriate CAPR was and the existing CAPR had not been completed. The attribute of effectiveness was not met because the actions taken to date would still result in a pressurized system open to the turbine deck under manual hotwell reject and water transfer conditions, which might result in water overflow. The attribute of long lasting (i.e. not temporary) was not met because the credited catch containments were temporary devices and the control of CST level remained under a temporary process (Operations Standing Order). In addition, the inspectors identified that the credited catch containments had been missing for several months.

Analysis:

The inspectors determined that the failure to follow procedure LS-AA-125-1001, Root Cause Analysis Manual, Attachment 12, in the implementation of CAPRs was a performance deficiency. Specifically, actions taken to date in response to the Unit 1 reactor trip on August 16, 2010, did not meet the attributes in procedure LS-AA-125-1001, Attachment 12, CAPR Attributes, for being timely, effective, and long-lasting (i.e. not temporary). In accordance with IMC 0612, Appendix B, the inspectors determined the issue was more than minor because the performance deficiency could be reasonably viewed as a precursor to a significant event and, if left uncorrected, has the potential to lead to a more significant safety concern. Specifically, the licensee continued to rely on administrative controls, temporary catch containments, and transferring water slowly to prevent water overflow events rather than eliminating the problem with a permanent modification to the stand pipes. As a result, the potential for water overflow events, while reduced, would not prevent recurrence.

The inspectors performed a significance review of the finding in accordance with IMC 0609, Attachment 4, Initial Characterization of Findings. In accordance with Table 2, the inspectors determined the issue affected the Transient Initiator Contributor function of the Initiating Events Cornerstone. The inspectors answered No to the Transient Initiators questions in Table 4a and, as a result, the finding screened as having very low safety significance (Green).

This finding had an associated cross-cutting aspect in the CAP component of the PI&R cross-cutting area. Specifically, the licensee did not take timely and appropriate corrective actions to prevent recurrence in response to the August 16, 2010, Unit 1 reactor trip P.1(d).

Enforcement:

The inspectors determined that this finding does not involve any violation of regulatory requirements. The licensee entered the issue into the CAP as IR 1395327.

(FIN 05000456/2012007-03; 05000457/2012007-03; Untimely Completion of a Corrective Action to Prevent Recurrence)

.2 Assessment of the Use of Operating Experience

a. Inspection Scope

The inspectors reviewed the licensees implementation of the 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 Based on the results of the inspection, the inspectors concluded that 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 various discussions with licensee staff, several licensee personnel commented favorably on the use of OPEX in their daily activities. Although, in general, OPEX was effectively used at the station, in one case, OPEX was not properly evaluated as discussed below.

c. Findings

Failure to Follow Corrective Action Program Procedure

Introduction:

The inspectors identified a finding of very low safety significance (Green)and an associated NCV of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, when licensee personnel failed to initiate an IR in accordance with the CAP procedure. Specifically, the licensee failed to initiate an IR and perform an operability determination during a 10 CFR Part 21 Notification evaluation.

Description:

On January 14, 2011, ABB Inc. (ABB) issued a 10 CFR Part 21 Notification associated with potential defects in overcurrent relays. The potential concern dealt with seismic specifications of COM 5, COM 9, and COM 11 relays. ABB stated that the zero period acceleration rating on its quality Certificate of Conformance document was incorrect, whereas a higher g value was reported. The licensee completed and approved OPEX evaluation 1165423, ENS [Event Notification System] 46545 - Part 21 Notification of Potential Defect for Overcurrent Relays, on April 29, 2011, after they reviewed the information.

Licensee staff determined during the OPEX evaluation that COM 5 and COM 11 relays were installed in safety-related 6.9 kilovolt (kV) switchgear in the plant as documented in Blocks I and III of the evaluation.

Block II of the evaluation required the OPEX evaluator to:

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 evaluator documented in his response that it was not possible to make an operability determination at that time because there was inadequate information from the relay vendor, ABB. The licensee further documented their response as:

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.

Block IV of the evaluation stated, in part, that, an IR must be initiated for any/all conditions adverse to quality that were identified in this evaluation. The licensee staff, during their review, did not identify the potential seismic qualifications of the relays as a condition adverse to quality (CAQ), and therefore did not initiate an IR. The licensees CAP procedure, LS-AA-125, Step 4.1.2, stated that:

If at any time a SCAQ or CAQ or any question of either current or past Operability/Reportability arises, then initiate an issue report in accordance with LS-AA-120.

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 />.

Step 1.2 of Procedure OP-AA-108-115, Operability Determinations, required that:

Whenever the ability of an SSC (structure, system, or component) to perform its specified safety function is called into question, operability must be determined from a detailed examination of the deficiency.

Step 4.1.2 of Procedure OP-AA-108-115 stated:

If the Originator or Supervisor identifies any potential operability or reportability issues, then the Originator or Supervisor shall personally CONTACT Operations Shift Management of the affected unit and DISCUSS the issue.

The inspectors determined that the OPEX evaluator failed to initiate an IR and submitted it to the operations shift management for their review once the OPEX evaluator identified that potentially degraded safety-related components were installed in the plant. An operability determination was never performed. On February 28, 2012 the licensee completed design analysis BYR12-025/BRW-12-0033-E, Review ABB Seismic Qualification Report for COM Overcurrent Relays Installed in Westinghouse 6.9 kV Switchgear (ABB Report No. CTR-COM-SUM, Rev. 01), and determined that the seismic qualification of the relays was suitable for their intended applications in the 6.9 kV switchgear. However, if the analysis had determined that the seismic qualification had been inadequate the plant would have operated for 10 months with the degraded components.

The inspectors determined that the OPEX evaluation was performed by staff at the Byron Station and then incorporated into the Braidwood Station evaluation. During the 2011 Problem Identification and Resolution Inspection at Byron (ADAMS Accession Number ML112910140), the NRC inspectors identified a similar concern with Byrons evaluation. Licensee staff at Braidwood was not aware of the issue at Byron.

The licensee entered this issue into their CAP as IR 1378432, Braidwood Wasnt Notified of a Byron OP Evaluation, and the operations shift manager determined that there were no past operability or reportability issues. The conclusion was documented in design analysis BYR12-025/BRW-12-0033-E.

Analysis:

The inspectors determined that the failure to initiate IRs in accordance with the CAP procedure was contrary to 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, and was a performance deficiency.

Specifically, the licensee failed to initiate an IR and perform an operability determination during a 10 CFR Part 21 Notification evaluation.

The finding was determined to be more than minor because the finding, if left uncorrected, could become a more significant safety concern. Specifically, if operations staff is not made aware of potentially degraded safety-related components they may not perform an operability determination and continue operating the plant with the degraded components. The inspectors concluded this finding was associated with the Mitigating Systems Cornerstone.

The inspectors determined the finding could be evaluated using the Significance Determination Process in accordance with IMC 0609, Significance Determination Process, Attachment 0609.04, Phase 1 - Initial Screening and Characterization of Findings, Table 4a, Characterization Worksheet for IE, MS, and BI Cornerstones, for the Mitigating Systems Cornerstone. The inspectors confirmed that the finding did not result in a loss of operability or functionality per Part 9900, Technical Guidance, Operability Determination Process for Operability and Functional Assessment, because the licensee was able to demonstrate that the seismic qualification of the relays was suitable for their intended applications in the 6.9 kV switchgear. Therefore, this finding was of very low safety significance (Green).

This finding had a cross-cutting aspect in the Operating Experience component of the PI&R cross-cutting area because the licensee did not systematically evaluate and communicate relevant operating experience to affected internal stakeholders.

Specifically, the individual performing the 10 CFR Part 21 notification evaluation did not communicate to operations personnel that a potentially degraded component was installed in safety-related equipment in the plant P.2(a).

Enforcement:

Title 10 CFR Part 50, Appendix B, Criterion 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. Procedure LS-AA-125, Revision 16, Corrective Action Program (CAP) Procedure, is a quality procedure and requires, in part, that If at any time a SCAQ or CAQ or any question of either current or past Operability/Reportability arises, then initiate an issue report in accordance with LS-AA-120. Procedure LS-AA-120, Revision 14, Issue Identification and Screening Process, requires that all nuclear personnel and contractors identify any conditions that could have an undesirable effect on the performance of equipment, personnel, or organizations and properly document the issue. LS-AA-120 also requires that operations shift management takes appropriate immediate actions.

Contrary to the above, from April 29, 2011 until February 28, 2012, the licensee failed to follow the instructions in accordance with Procedure LS-AA-125. Specifically, the licensee failed to initiate an issue report and perform an operability determination once an incorrect zero period acceleration rating were identified for safety-related components during a 10 CFR Part 21 Notification evaluation.

Because this violation was of very low safety significance and it was entered into the licensees CAP as IR 1378432, this violation is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy. (NCV 05000456/2012007-04; 05000457/2012007-04, Failure to Follow Corrective Action Program Procedure)

.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 Based on the results of the inspection, 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 had identified a number of Significance Level 3 issues for the site to address since the last biennial PI&R inspection. These issues included weaknesses in management oversight of the CAP. Although NOS had lifted their escalation (increased oversight) of the CAP, the inspectors still had concerns on the licensees ability to maintain this focus, as evidenced by the findings and observations described above.

c. Findings

No findings were identified.

.4 Assessment of Safety Conscious Work Environment

a. Inspection Scope

The inspectors interviewed selected Braidwood 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 ECP with the ECP coordinators, and reviewed ECP activities to identify any emergent issues or potential trends. The inspectors also assessed the licensees 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 Braidwood 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 indicated that management had been supportive of the CAP by providing time and resources for employee to generate their own issue reports.

The staff also expressed a willingness to challenge actions or decisions that they believed were unsafe. All employees interviewed noted that any safety issue could be freely communicated to supervision and safety significant issues were being corrected.

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.

c. Findings

No findings were identified.

4OA6 Management Meetings

a.

Exit Meeting Summary

On September 29, 2012, the inspectors presented the inspection results to Mr. J. Bashor, 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

J. Bashor, Acting Plant Manager

D. Baracco, Radiation Protection Supervisor

S. Butler, Site Corrective Action Program Manager

C. VanDenburgh, Regulatory Assurance Manager

J. Rappeport, Chemistry Manager

R. Radulovich, Nuclear Oversight Manager

B. Schipiour, Maintenance Director

M. Sears, Engineering Programs Manager

G. Stopka, Shift Operations Superintendent

NRC

E. Duncan, Branch Chief

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

05000456/2012007-01 NCV Non-Conforming Piping Condition Not Corrected (Section 4OA2.1.b.2.ii)

05000456/2012007-02 NCV Surveillance Procedure Not Followed (Section 4OA2.1.b.3.ii)

05000456/2012007-03; FIN Untimely Completion of a Corrective Action to Prevent

05000457/2012007-03 Recurrence (Section 4OA2.1.b.3.ii)

05000456/2012007-04; NCV Failure to Follow Corrective Action Program Procedure

05000457/2012007-04 (Section 4OA2.2.c)

Closed

05000456/2012007-01 NCV Non-Conforming Piping Condition Not Corrected (Section 4OA2.1.b.2.ii)

05000456/2012007-02 NCV Surveillance Procedure Not Followed (Section 4OA2.1.b.3.ii)

05000456/2012007-03; FIN Untimely Completion of a Corrective Action to Prevent

05000457/2012007-03 Recurrence (Section 4OA2.1.b.3.ii)

05000456/2012007-04; NCV Failure to Follow Corrective Action Program Procedure

05000457/2012007-04 (Section 4OA2.2.c)

Discussed

None Attachment