IR 05000266/2012004

IR 05000266-12-004, 05000301-12-004 & 07200005-12-001; NextEra Energy Point Beach, LLC; 07/01/2012 - 09/30/2012; Point Beach Nuclear Plant, Units 1 and 2, NRC Integrated Inspection Report

ML12312A294
Person / Time
Site:	Point Beach
Issue date:	11/07/2012
From:	Michael Kunowski NRC/RGN-III/DRP/B5
To:	Meyer L Point Beach
References
IR-12-004
Download: ML12312A294 (84)

Text

UNITED STATES ber 7, 2012

SUBJECT:

POINT BEACH NUCLEAR PLANT, UNITS 1 AND 2 NRC INTEGRATED INSPECTION REPORT 05000266/2012004 AND 05000301/2012004, AND 07200005/2012001

Dear Mr. Meyer:

On September 30, 2012, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Point Beach Nuclear Plant, Units 1 and 2. The enclosed report documents the results of this inspection, which were discussed on October 2, 2012, with you and 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.

Ten NRC-identified findings of very low safety significance (Green) were identified during this inspection. Nine of these were determined to involve violations of NRC requirements.

Additionally, the NRC has determined that two of these violations involved traditional enforcement Severity Level IV violations. Further, a licensee-identified violation which was determined to be of very low safety significance is listed in this report. The NRC is treating these violations as non-cited violations (NCVs) consistent with Section 2.3.2 of the Enforcement Policy.

If you contest the violations or significance of these NCVs, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington DC 20555-0001; with copies to the Regional Administrator, Region III; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at Point Beach Nuclear Plant.

If you disagree with a cross-cutting aspect assignment 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 Point Beach Nuclear Plant. 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 System (PARS)

component of NRC's Agencywide Document Access and Management System (ADAMS).

ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Michael A. Kunowski, Branch Chief Branch 5 Division of Reactor Projects Docket Nos. 50-266; 50-301;72-005 License Nos. DPR-24; DPR-27

Enclosure:

Inspection Report 05000266/2012004; 05000301/2012004; 07200005/2012001 w/Attachment: Supplemental Information

REGION III==

Docket Nos: 05000266; 05000301; 07200005 License Nos: DPR-24; DPR-27 Report No: 05000266/2012004; 05000301/2012004; 07200005/2012001 Licensee: NextEra Energy Point Beach, LLC Facility: Point Beach Nuclear Plant, Units 1 and 2 Location: Two Rivers, WI Dates: July 1, 2012, through September 30, 2012 Inspectors: S. Burton, Senior Resident Inspector M. Thorpe-Kavanaugh, Resident Inspector J. Jandovitz, Project Engineer R. Krsek, Senior Resident Inspector (Kewaunee)

C. Zoia, Operations Engineer M. Learn, Reactor Engineer V. Meghani, Reactor Inspector K. Carrington, Reactor Engineer P. Cardona-Morales, Emergency Response Specialist Approved by: Michael A. Kunowski, Branch Chief Branch 5 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

Inspection Report (IR) 05000266/2012004, 05000301/2012004, 07200005/2012001; 07/01/2012 - 09/30/2012; Point Beach Nuclear Plant, Units 1 and 2; and routine ISFSI inspection; Adverse Weather Protection, Maintenance Risk Assessments and Emergent Work Control, Operability Determinations and Functional Assessments, Plant Modifications, Outage Activities, Identification and Resolution of Problems, and Other Activities.

This report covers a 3-month period of inspection by resident inspectors and announced baseline inspections by regional inspectors. Ten findings were identified by the inspectors.

The findings were considered non-cited violations (NCVs) of NRC regulations. The significance of most findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP). Findings for which the SDP does not apply may be Green or be assigned a severity level after NRC management review.

Cross-cutting aspects are determined using IMC 0310, Components Within The Cross-Cutting Areas dated October 2011. All violations of NRC requirements are dispositioned in accordance with the NRCs Enforcement policy dated July 7, 2012. 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.

NRC-Identified

and Self-Revealed Findings

Cornerstone: Initiating Events

Green.

The inspectors identified a finding of very low safety significance for the licensees failure to maintain control over the proper storage and placement of materials that were classified as high winds/tornado hazards, within the risk significant areas of the outdoors protected area, in accordance with station procedure NP 1.9.6, Plant Cleanliness and Storage. Specifically, the inspectors identified unsecured material on wood pallets near the station transformers 1X-04 and 2X-04, which provided offsite power to both units. The licensee took immediate corrective action to remove the material. The issue was entered into the licensees corrective action program for resolution as action request AR01788119 for evaluation and development of additional corrective actions.

The finding was determined to be more than minor in accordance with IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Screening, dated September 7, 2012, because it was associated with the Initiating Events Cornerstone attribute of equipment performance and adversely affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Additionally, if left uncorrected, it would have the potential to lead to a more significant safety concern. Specifically, the loose material could have affected offsite power during periods of high winds. The inspectors evaluated the finding using IMC 0609, Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings, Tables 2 and 3, and Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 1 for the Initiating Events Cornerstone, dated June 19, 2012. The inspectors answered No to the Exhibit 1 questions in Appendix A for transient initiators and support system initiators. Therefore, the inspectors determined the finding to be of very low safety significance. This finding has a cross-cutting aspect in the area of human performance, work practices, because licensee personnel did not appropriately plan work activities by incorporating job site conditions, including environmental conditions, which might have impacted plant structures, systems, and components (H.3(a)). (Section 1R01)

Green.

The inspectors identified a finding of very low safety significance and associated non-cited violation of 10 CFR 50.55a(g)(4) because the licensee failed to identify and evaluate an American Society of Mechanical Engineers (ASME) Code Class pressure boundary flaw. Specifically, between May 22 and June 26, 2012, the licensee did not identify that leakage in the Unit 2 containment from an unknown source was from a weld in the steam generator A blowdown line, an ASME Section XI Code Class 2 high energy component. The issue was entered into the licensees corrective action program as action requests AR01789202 and AR01797798 for evaluation and development of corrective actions.

The finding was determined to be more than minor in accordance with IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Screening, dated September 7, 2012, because it was associated with the Initiating Events Cornerstone attribute of equipment performance and adversely affected the reliability of the steam generation systems (steam generator, feedwater, or main steam); thereby, directly impacting the cornerstone objective to limit the likelihood of events that upset plant stability during power operations. Specifically, the inspectors determined that any potential (and subsequently actual) failure location represented both a containment barrier during a loss of coolant accident and a reactor pressure system boundary during a steam generator tube failure event, in addition to being a potential transient initiator if the leakage became more significant. The inspectors evaluated the finding using IMC 0609, Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings,

Tables 2 and 3, dated June 19, 2012, and Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 1 for the Initiating Events Cornerstone, dated June 19, 2012. The inspectors answered No to the Exhibit 1 questions in Appendix A for transient initiators and support system initiators. Therefore, the inspectors determined the finding to be of very low safety significance. This finding has a cross-cutting aspect in the area of human performance, conservative assumptions.

Specifically, the licensee failed to use conservative assumptions in decision-making because it developed an operability evaluation demonstrating that continued full power operation was acceptable without reasonable assurance that the leakage was from a mechanical joint, rather than developing reasonable assurance or providing physical evidence, either indirectly or by observation, that the leakage was not pressure boundary leakage (H.1(b)). (Section 1R15)

Cornerstone: Mitigating Systems

Green.

The inspectors identified a finding of very low safety significance and associated non-cited violation of 10 CFR 50.65(a)(4) because the licensee failed to properly manage and assess risk for various emergent work activities. Specifically, the licensee failed to manage the risk associated with the gas turbine generator (G-05) failure out-of-service duration, the G-05 unavailability when on the turning gear, and the Unit 1 turbine electrohydraulic control (EHC) system in manual. The issue was entered into the licensees corrective action program as action requests AR01808661 and AR01787706 for evaluation and development of corrective actions.

The finding was determined to be more than minor in accordance with IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Screening, dated September 7, 2012, because the failure to properly manage and assess risk, if left uncorrected, would have the potential to become a more significant safety concern. Specifically, the inspectors determined that the addition of a Unit 1 transient initiator and of G-05 modeled as out-of-service into the licensees safety monitor program for risk was more than minor because the licensees risk assessment was based on incorrect assumptions that changed the outcome of the assessment. The inspectors evaluated the finding using IMC 0609, Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings, Tables 2 and 3, dated June 19, 2012, and Appendix K,

Maintenance Risk Assessment And Risk Management Significance Determination Process, dated May 19, 2005. The inspectors determined that the finding was a mitigating systems contributor, evaluated the risk deficit for each instance, and found that the issue screened as having very low safety significance. This finding has a cross-cutting aspect in the area of human performance, work practices, because the licensee failed to define and effectively communicate expectations regarding procedural compliance and ensure personnel follow procedures. Specifically, in all instances the licensee failed to communicate expectations regarding compliance as required by station nuclear procedure (NP) 1.1.4, and ensure personnel followed implementing procedure NP 10.3.7, for risk management (H.4(b)). (Section 1R13)

Green.

The inspectors identified a finding of very low safety significance and associated non-cited violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, for a deficiency in weld evaluations in the licensee design calculation of the new missile protection steel barriers. These barriers were installed for protection of the emergency diesel generators G-01 and G-02 exhaust pipes from a tornado missile strike.

Specifically, the inspectors identified two examples where critical welds were not adequately addressed in the calculation. The issue was entered into the licensees corrective action program as action requests AR01771762 and AR01772431 for evaluation and development of corrective actions.

The finding was determined to be more than minor in accordance with IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Screening, and Appendix E, Example of Minor Issues, dated August 11, 2009, and found that it was similar to Example 3a and it was associated with the Mitigating Systems Cornerstone attribute of Design Control and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The inspectors evaluated the finding using IMC 0609,

Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings, Tables 2 and 3, dated June 19, 2012, and Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 1 for the Mitigating Systems Cornerstone, dated June 19, 2012. The inspectors answered Yes to Exhibit 2, Question A.1 in Appendix A for mitigating structures, systems, and components, and functionality. Therefore, the inspectors determined the finding to be of very low safety significance. This finding has a cross-cutting aspect in the area of human performance, work practices, because the licensee failed to ensure supervisory oversight of the contractor activities to support nuclear safety. Specifically, in the examples noted, the licensee failed to adequately review the calculation performed by the contractor to verify that the assumptions and engineering judgments were adequately justified and consistent with the installation (H.4(c)). (Section 1R18)

Green.

The inspectors identified a finding of very low safety significance and associated non-cited violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions,

Procedures, and Drawings, for the failure to remove a plastic bag of transient materials that could interact with the containment sump recirculation strainer. Specifically, while performing the containment closure inspection prior to reactor startup, the inspectors identified a large plastic bag containing mop-heads and cleaning materials that, if left in containment, could interact with the containment recirculation sump suction strainer.

The licensee took immediate corrective action to remove the items from containment.

The issue was entered into the licensees corrective action program for resolution as action requests AR01781331 and AR01808631 for evaluation and development of additional corrective actions.

The finding was determined to be more than minor in accordance with IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Screening, dated September 7, 2012, because it was associated with the Mitigating System Cornerstone attribute of equipment performance and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the low head safety injection system availability and reliability could be reduced by material clogging the recirculation sump suction strainer. The inspectors evaluated the finding using IMC 0609, Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings,

Tables 2 and 3, dated June 19, 2012, and Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 2 for the Mitigating Systems Cornerstone, dated June 19, 2012. The inspectors answered Yes to Exhibit 2, Question A.1 in Appendix A for mitigating structures, systems, and components, and functionality.

Therefore, inspectors determined the finding to be of very low safety significance. The finding did not have a cross-cutting aspect because the cause was identical to the cause for the boric acid not being removed from containment isolation valve 2SC-955, as required by procedure, an issue also identified during the inspection, and the cross-cutting aspect was captured by that issue. (Section 1R20.1(2))

Green.

The inspectors identified a finding of very low safety significance and associated non-cited violation of Technical Specification 5.4, Procedures. Specifically, the licensee failed to maintain its emergency operating procedures (EOPs) with the safety-significant changes provided in the Westinghouse Owners Group Emergency Response Guidelines (WOG ERGs), Revision 2. The issue was entered in the licensees corrective action program as action request AR01779635 for evaluation and development of corrective actions.

The finding was determined to be more than minor in accordance with IMC 0612, "Power Reactor Inspection Reports, Appendix B, Issue Screening, dated September 7, 2012, because it was associated with the Mitigating Systems Cornerstone attribute of procedure quality and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the inspectors determined that the failure to update EOPs to implement Revision 2 of the WOG ERGs significantly beyond the current industry standard of two years would result in a delay when terminating Primary-To-Secondary Leakage during a steam generator tube rupture event. The inspectors evaluated the finding using IMC 0609, Significance Determination Process,

Attachment 0609.04, Initial Characterization of Findings, Tables 2 and 3, dated June 19, 2012, and Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 2 for the the Mitigating Systems Cornerstone, dated June 19, 2012. The inspectors answered Yes to Exhibit 2, Question A.1 in Appendix A for mitigating structures, systems, and components, and functionality. Therefore, the inspectors determined the finding to be of very low safety significance. This finding has a cross-cutting aspect in the area of human performance, resources, because the licensee failed to assure resources were available and adequate to complete the WOG ERG, Revision 2 EOP updates in a timely manner commensurate with risk and safety (H.2(c)). (Section 4OA5.2)

Cornerstone: Barrier Integrity

Green.

The inspectors identified a finding of very low safety significance and associated non-cited violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions,

Procedures, and Drawings, for the failure to clean boric acid from the Unit 2 reactor coolant system hot leg sample isolation valve 2SC-955. Specifically, during the containment closeout tour performed by the inspectors, the inspectors identified that boric acid leakage on valve 2SC-955 had not been cleaned as required by the boric acid program. The licensee subsequently cleaned the valve prior to restart of the reactor and entered the issue into its corrective action program for resolution as action requests AR01782290, AR01765986, AR01780951, and AR01797802, for evaluation and development of additional corrective actions.

The finding was determined to be more than minor in accordance with IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Screening, dated September 7, 2012, because it was associated with the Barrier Integrity Cornerstone attribute of reactor coolant system equipment and barrier performance and adversely affected the cornerstone objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events.

Additionally, if left uncorrected, it could impact the operators ability to verify a containment isolation actuation, thereby adversely affecting the cornerstone objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. The inspectors evaluated the finding using IMC 0609, Significance Determination Process, Attachment 0609.04,

Initial Characterization of Findings, Tables 2 and 3, dated June 19, 2012, and Appendix A, The Significance Determination Process (SDP) for Findings At-Power,

Exhibit 2 for the Mitigating Systems Cornerstone, dated June 19, 2012. The inspectors answered Yes to Exhibit 2, Question A.1 in Appendix A for mitigating structures, systems, and components, and functionality. Therefore, the inspectors determined the finding to be of very low safety significance. This finding has a cross-cutting aspect in the area of human performance, systematic processes, because the licensee failed to use a systematic process when making decisions related to the cleaning of boric acid components during the unplanned shutdown. Specifically, the licensees communications and interfaces for performing the activities and developing corrective actions were not approached rigorously and systematically when the duration of the unplanned outage was significantly shortened, and plant startup timelines modified the expected boric acid cleaning plans (H.1(a)). (Section 1R20.1(1))

Green.

The inspectors identified a finding of very low safety significance and associated non-cited violation of 10 CFR Part 50, Appendix B, Criterion V, "Instructions,

Procedures, and Drawings," for the licensees failure to have adequate procedures in place to ensure that heavy loads were operated safely within the primary auxiliary building (PAB). Specifically, the inspectors determined that the licensee failed to incorporate minimum crane operating temperature limits into procedures to avoid brittle fracture of structural components below the nil-ductility transition temperature. The issue was entered into the licensees corrective action program for resolution as action request AR01783306 for evaluation and development of corrective actions which included revising procedures to identify the minimum operating temperature of the PAB crane.

The finding was determined to be more than minor in accordance with IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Screening, dated September 7, 2012, because it was associated with the Barrier Integrity Cornerstone attribute of procedure quality and adversely affected the cornerstone objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events because a PAB crane heavy load drop could cause damage to spent fuel. The inspectors evaluated the finding using IMC 0609,

Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings, Tables 2 and 3, dated June 19, 2012, and Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 3 for the Barrier Integrity Cornerstone, dated June 19, 2012. The inspectors answered No to Exhibit 3 questions in Appendix A for the spent fuel pool. Therefore, the inspectors determined the finding to be of very low safety significance. In accordance with IMC 0612, Section 06.03.c, a cross-cutting aspect will not be assigned to this finding as it has occurred outside of the nominal three-year period and is not representative of present performance.

(Section 4OA5.3(2))

===Cornerstone:

=

• Severity Level IV. The inspectors identified a Severity Level lV non-cited violation and associated finding of very low safety significance of 10 CFR 26.207(a), Waivers, for the licensees failure to perform multiple activities as required when licensed reactor operators in the shift manager (SM) position worked outage hours during the Unit 1 outage in fall 2011. Specifically, for each circumstance where an SM exceeded operating hours, the licensee did not meet the following requirements: a determination that the waiver is necessary to mitigate or prevent a condition adverse to safety; a face-to-face assessment of the individual to determine that there was reasonable assurance that the individual would be able to safely and competently perform his or her duties during the additional work period for which the waiver will be granted; and a circumstance did not exist that could not have been reasonably controlled because additional personnel could have been added to the shift to perform the related outage activities. The issue was entered into the licensees corrective action program for resolution as action request AR01797782, for evaluation and development of corrective actions.

The finding was determined to be more than minor in accordance with IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Screening, dated September 7, 2012, because if left uncorrected, the exclusion of workers from work hour controls could have led to a more significant safety concern due to personnel exceeding work hour limits while performing safety related or risk significant activities. Specifically, without proper fatigue assessments, incorrect assessment or directions could be provided by the SM for routine activities or during transient/emergency response. The inspectors evaluated the finding using IMC 0609, Significance Determination Process, Attachment 0609.04,

Initial Characterization of Findings, Tables 2 and 3, dated June 19, 2012, and Appendix M, Significance Determination Process Using Qualitative Criteria, dated

April 12, 2012. The inspectors determined that the finding was of very low safety significance because no deficiencies which affected risk significant structures, systems, or components occurred as a result of SM fatigue. This finding has a cross-cutting aspect in the area of problem identification and resolution, self and independent assessment, because the licensee failed to conduct sufficient in-depth self-assessments.

Specifically, the licensee conducted a self-assessment of the fatigue rule annually with its corporate licensing department giving the licensee the prior opportunity to identify and correct this issue had the self-assessments been more rigorous (P.3(a)).

(Section 4OA2.5)

• Severity Level IV. The inspectors identified a Severity Level lV non-cited violation of 10 CFR 72.146, Design Control, for the licensees failure to perform adequate evaluations to ensure compliance with 10 CFR 72.122(b)(2)(i) and 10 CFR 72.212(b)(6).

Specifically, the inspectors identified that the licensee failed to evaluate that the reactor site parameters, including analyses of earthquakes, were enveloped by the transfer cask design basis. The issue was entered into the licensees corrective action program for resolution as action request AR01780357, for evaluation and development of corrective actions.

The violation was determined to be more than minor in accordance with IMC 0612,

Power Reactor Inspection Reports, Appendix B, Issue Screening, and Appendix E,

Example of Minor Issues, dated August 11, 2009, and found that it was similar to Example 3i. Specifically, the licensees lack of evaluation did not assure cask integrity during a design basis earthquake and an additional calculation was required to evaluate the effects of the design basis earthquake during dry shielded canister processing operations in the primary auxiliary building on the cask decontamination stand in accordance with the Independent Spent Fuel Storage Installation (ISFSI)licensing/design basis analysis requirements. Consistent with the guidance in the NRC Enforcement Manual, Section 2.6.D, if a violation does not fit an example in the enforcement policy violation examples, it should be assigned a severity level:

(1) commensurate with its safety significance; and, (2) informed by similar violations addressed in the Violation Examples. Therefore, the inspectors determined violation screened as having very low safety significance (Severity Level IV). Specifically, following the inspection inquiry the licensee revised their calculations and determined that overturning and sliding of the transfer cask in the primary auxiliary building on the cask decontamination stand and in the spent fuel pool would not occur during the design basis earthquake. In accordance with Section 2.2 of the NRC Enforcement Policy,

ISFSIs are not subject to the Significance Determination Process (SDP) and, thus, traditional enforcement will be used for these facilities and thus a cross-cutting aspect is not assigned to this violation. In accordance with Section 2.2 of the NRC Enforcement Policy, ISFSIs are not subject to the SDP and, thus, traditional enforcement will be used for these facilities and thus a cross-cutting aspect is not assigned to this violation.

(Section 4OA5.3(1))

Licensee-Identified Violations

A violation of very low significance was identified by the licensee has been reviewed by the inspectors. Corrective actions planned or taken by the licensee have been entered into the licensees corrective action program. This violation and related corrective action tracking numbers are listed in Section 4OA7 of this report.

REPORT DETAILS

Summary of Plant Status

Unit 1 operated at full power levels with the following exceptions:

• reactor power was lowered to 50 percent to support turbine stop valve and atmospheric steam dump testing on July 22, 2012;

• the reactor was manually tripped on August 14, 2012, due to a load rejection and returned to full power on August 19, 2012; and

• reactor power was reduced to 55 percent power for main feedwater (FW) pump repairs on August 31, 2012, and returned to full power on September 5, 2012.

Unit 2 began the quarter shutdown due to a manual reactor trip and returned to full power operation on July 4, 2012. Unit 2 operated at or near full power levels for the remainder of the entire inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

.1 Readiness of Offsite and Alternate AC Power Systems

a. Inspection Scope

The inspectors verified that plant features and procedures for operation and continued availability of offsite and alternate alternating current (AC) power systems during adverse weather were appropriate. The inspectors reviewed the licensees procedures affecting these areas and the communications protocols between the transmission system operator (TSO) and the plant to verify that the appropriate information was being exchanged when issues arose that could impact the offsite power system. Examples of aspects considered in the inspectors review included:

• the coordination between the TSO and the plant during off-normal or emergency events;

• the explanations for the events;

• the estimates of when the offsite power system would be returned to a normal state; and

• the notifications from the TSO to the plant when the offsite power system was returned to normal.

The inspectors also verified that plant procedures addressed measures to monitor and maintain availability and reliability of both the offsite AC power system and the onsite alternate AC power system prior to or during adverse weather conditions. Specifically, the inspectors verified that the procedures addressed the following:

• the actions to be taken when notified by the TSO that the post-trip voltage of the offsite power system at the plant would not be acceptable to assure the continued operation of the safety-related (SR) loads without transferring to the onsite power supply;

• the compensatory actions identified to be performed if it would not be possible to predict the post-trip voltage at the plant for the current grid conditions;

• a re-assessment of plant risk based on maintenance activities which could affect grid reliability, or the ability of the transmission system to provide offsite power; and

• the communications between the plant and the TSO when changes at the plant could impact the transmission system, or when the capability of the transmission system to provide adequate offsite power was challenged.

Documents reviewed are listed in the Attachment to this report. The inspectors also reviewed CAP items to verify that the licensee was identifying adverse weather issues at an appropriate threshold and entering them into the CAP in accordance with station corrective action procedures.

This inspection constituted one readiness of offsite and alternate AC power systems sample as defined in Inspection Procedure (IP) 71111.01-05.

b. Findings

Failure to Adequately Control Materials Classified As High Winds/Tornado Hazards

Introduction:

The inspectors identified a finding of very low safety significance (Green)for the licensees failure to maintain control over the proper storage and placement of materials that were classified as high winds/tornado hazards, within the risk significant areas of the outdoors protected area, near electrical transformers, in accordance with a station procedure.

Description:

On July 6, 2012, after returning from a walkdown of the transmission yard, the inspectors noted material in the vicinity of transformers 1X-04 and 2X-04. These transformers supply offsite power to both units, respectively. In particular, the inspector was concerned with a number of pieces of unsecured sheet metal, approximately 2 feet square and about 1/4 inch thick, on a wooden pallet.

The inspectors were concerned that this material, combined with high velocity winds, increased the potential to lose an offsite power transformer because the metal sheets could become a missile hazard and damage the offsite power transformer or power lines.

Station nuclear procedure NP 1.9.6, Plant Cleanliness and Storage, Section 4.9.1, stated that, Unsecured objects that can be picked up by 73-135 mph winds can be thrown against equipment with enough force to disable them are considered missile hazards. Section 4.9.4(b) identified loose sheets of metal as examples of high wind missile hazards. Section 4.9.3 stated that all areas within the owner-controlled area shall be free of high wind missile hazards. Specific locations were listed, including the Unit 1 and Unit 2 transformer areas, switchyard areas, and warehouse areas, and were included specifically on a checklist contained in this procedure. While transformers 1X-04 and 2X-04 were not mentioned specifically, discussions with plant personnel indicated these that transformers are covered by this checklist. Additionally, Section 4.9.5 required weekly inspections for high wind missile hazards using the procedure checklist. The checklist from the walkdown conducted on July 3, 2012, was reviewed by the inspectors. No high wind hazards were noted, but the location identified for the switchyard area was not completed.

After this issue was identified to the shift manager (SM) by the inspectors, all the material was promptly removed. The inspectors noted that procedure NP 1.9.6, Section 4.9.8, required an AR to be initiated to document all potential high wind missile hazards identified during inspections, even if the hazards have been removed.

Subsequently, condition report AR01788119 was generated on July 26, 2012 by the regulatory assurance department, and AR01790394 was generated on August 2, 2012, to address why an AR was not initiated when the material was identified on July 3.

Although no high wind conditions existed, station log entries for July 3 through July 6, 2012, noted chances of storms in the area with associated winds described as gusty and strong. Winds speed data from meteorological tower 1 on July 4, 2012, did show wind speed spiking above 35 miles per hour, but none exceeding 50 miles per hour.

The site had similar findings documented in NRC Inspection Reports (IRs) 2008003 and 2009006.

Analysis:

The inspectors determined that the licensees failure to control loose debris near risk-significant equipment was contrary to the standards contained in NP 1.9.6 and was a performance deficiency that was within the licensee ability to foresee and correct and warranting further review.

The finding was determined to be more than minor in accordance with Inspection Manual Chapter (IMC) 0612, Power Reactor Inspection Reports, Appendix B, Issue Screening, dated September 7, 2012, because it was associated with the Initiating Events Cornerstone attribute of equipment performance and adversely affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations.

Additionally, if left uncorrected, it would have the potential to lead to a more significant safety concern. Specifically, the loose material could have affected offsite power during periods of high winds.

The inspectors evaluated the finding using IMC 0609, Significance Determination Process [SDP], Attachment 0609.04, Initial Characterization of Findings, Tables 2 and 3, and Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 1 for the Initiating Events Cornerstone, dated June 19, 2012. The inspectors answered No to the Appendix A, Exhibit 1 questions for transient initiators; did the finding contribute to both the likelihood of a reactor trip and the likelihood that mitigation equipment or functions would not be available; and support system initiators; and did the finding involve the complete or partial loss of a support system that contributes to the likelihood of, or cause, an initiating event and affected mitigation equipment. Therefore, inspectors determined the finding to be of very low safety significance (Green).

The inspectors determined that the finding had a cross-cutting aspect in the area of human performance, work practices, because licensee personnel did not appropriately plan work activities by incorporating job site conditions, including environmental conditions, which might impact plant structures, systems, and components (H.3(a)).

Enforcement:

The licensees failure to control loose debris near risk-significant equipment was not an activity affecting quality subject to 10 CFR Part 50, Appendix B, nor was a procedure required by license conditions or technical specifications (TSs)violated. Therefore, while a performance deficiency existed, this finding does not involve enforcement action because no violation of regulatory requirements was identified.

There were no actual safety consequences because transformers 1X-04 and 2X-04 remained capable of performing their safety function. The licensee took immediate corrective action to remove the material and documented the issue in the CAP as AR01788119 for evaluation and development of additional corrective actions. Because this finding does not involve a violation and is of very low safety or security significance, it is identified as a FIN (FIN 05000266/2012004-01; 05000301/2012004-01, Failure to Adequately Control Materials Classified As High Winds/Tornado Hazards).

1R04 Equipment Alignment

.1 Quarterly Partial System Walkdowns

a. Inspection Scope

The inspectors performed partial system walkdowns of the following risk-significant systems:

• station blackout gas turbine G-05 during high grid demand conditions;

• instrument air following maintenance;

• Unit 1 turbine-driven auxiliary feedwater (TDAFW) system following testing/startup Unit 1 trip;

• Unit 2 motor-driven auxiliary FW system following quarterly testing;

• Unit 2 component cooling water (CCW) system with pump A out-of-service (OOS);

• Unit 1 safeguards service water (SW) system following SW pump re-alignment;

• Unit 2 train A emergency core cooling system (ECCS) following system venting; and

• emergency diesel generator (EDG) G-02 with G-01 OOS for maintenance.

The inspectors selected these systems based on their risk significance relative to the Reactor Safety Cornerstones at the time they were inspected. The inspectors attempted to identify any discrepancies that could impact the function of the system and, therefore, potentially increase risk. The inspectors reviewed applicable operating procedures, system diagrams, Final Safety Analysis Report (FSAR), TS requirements, outstanding work orders (WOs), condition reports (CRs), and the impact of ongoing work activities on redundant trains of equipment in order to identify conditions that could have rendered the systems incapable of performing their intended functions. The inspectors also walked down accessible portions of the systems to verify system components and support equipment were aligned correctly and operable. The inspectors examined the material condition of the components and observed operating parameters of equipment to verify that there were no obvious deficiencies. The inspectors also verified that the licensee had properly identified and resolved equipment alignment problems that could cause initiating events or impact the capability of mitigating systems or barriers and entered them into the CAP with the appropriate significance characterization.

Documents reviewed are listed in the Attachment to this report.

These activities constituted eight partial system walkdown samples as defined in IP 71111.04-05.

b. Findings

No findings were identified.

.2 Semi-Annual Complete System Walkdown

a. Inspection Scope

On September 17, 2012, the inspectors performed a complete system alignment inspection of the fire protection (FP) system to verify the functional capability of the system. This system was selected because it was considered both safety significant and risk significant in the licensees probabilistic risk assessment. The inspectors walked down the system to review mechanical and electrical equipment lineups; electrical power availability; system pressure and temperature indications, as appropriate; component labeling; component lubrication; component and equipment cooling; hangers and supports; operability of support systems; and to ensure that ancillary equipment or debris did not interfere with equipment operation. A review of a sample of past and outstanding WOs was performed to determine whether any deficiencies significantly affected the system function. In addition, the inspectors reviewed the CAP database to ensure that system equipment alignment problems were being identified and appropriately resolved. Documents reviewed are listed in the to this report.

These activities constituted one complete system walkdown sample as defined in IP 71111.04-05.

b. Findings

No findings were identified.

1R05 Fire Protection

.1 Routine Resident Inspector Tours

a. Inspection Scope

The inspectors conducted FP walkdowns which were focused on availability, accessibility, and the condition of firefighting equipment in the following risk-significant plant areas:

• fire zone 681 (G-05 building);

• fire zone 142 (CCW pump);

• fire zone 304N (Unit 2 TDAFW pump area) (partial);

• fire zone 304S (Unit 1 TDAFW pump area) (partial);

• fire zone 306 (battery room D-06) (partial);

• fire zone 307 (battery room D-05) (partial);

• fire zone 777 (G-04 switchgear room); and

• fire zone 773 (G-03 switchgear room).

The inspectors reviewed areas to assess if the licensee had implemented an FP program that adequately controlled combustibles and ignition sources within the plant, effectively maintained fire detection and suppression capability, maintained passive FP features in good material condition, and implemented adequate compensatory measures for OOS, degraded, or inoperable FP equipment, systems, or features in accordance with the licensees fire plan. The inspectors selected fire areas based on their overall contribution to internal fire risk as documented in the plants Individual Plant Examination of External Events with later additional insights, their potential to impact equipment which could initiate or mitigate a plant transient, or their impact on the plants ability to respond to a security event. Using the documents listed in the Attachment to this report, the inspectors verified that fire hoses and extinguishers were in their designated locations and available for immediate use; that fire detectors and sprinklers were unobstructed; that transient material loading was within the analyzed limits; and fire doors, dampers, and penetration seals appeared to be in satisfactory condition. The inspectors also verified that minor issues identified during the inspection were entered into the licensees CAP. Documents reviewed are listed in the Attachment to this report.

These activities constituted four completed and four partial quarterly fire protection inspection samples as defined in IP 71111.05-05.

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program

.1 Resident Inspector Quarterly Review of Licensed Operator Requalification

a. Inspection Scope

On July 24, 2012, the inspectors observed a crew of licensed operators in the plants simulator during licensed operator requalification training to verify that operator performance was adequate, evaluators were identifying and documenting crew performance problems, and training was being conducted in accordance with licensee procedures. The inspectors evaluated the following areas:

• licensed operator performance;

• crews clarity and formality of communications;

• ability to take timely actions in the conservative direction;

• prioritization, interpretation, and verification of annunciator alarms;

• correct use and implementation of abnormal and emergency procedures;

• control board manipulations;

• oversight and direction from supervisors; and

• ability to identify and implement appropriate TS actions and Emergency Plan (EP) actions and notifications.

The crews performance in these areas was compared to pre-established operator action expectations and successful critical task completion requirements. Documents reviewed are listed in the Attachment to this report.

This inspection constituted one quarterly licensed operator requalification program simulator sample as defined in IP 71111.11.

b. Findings

No findings were identified.

.2 Resident Inspector Quarterly Observation of Heightened Activity or Risk

a. Inspection Scope

On July 5, 2012, the inspectors observed synchronization of the Unit 2 main generator to the offsite grid. This was an activity that required heightened awareness or was related to increased risk. The inspectors evaluated the following areas:

• licensed operator performance;

• crews clarity and formality of communications;

• ability to take timely actions in the conservative direction;

• prioritization, interpretation, and verification of annunciator alarms;

• correct use and implementation of procedures;

• control board manipulations; and

• oversight and direction from supervisors The performance in these areas was compared to pre-established operator action expectations, procedural compliance and task completion requirements. Documents reviewed are listed in the Attachment to this report.

This inspection constituted one quarterly licensed operator heightened activity/risk sample as defined in IP 71111.11.

b. Findings

No findings were identified.

.3 Unresolved Item (URI) Closure - Potential Failure to Correctly Implement a Systems

Approach to Training for the Licensed Operator Requalification Program (71111.11Q)

a. Inspection Scope

The inspectors reviewed a sample of simulator and classroom training provided, CRs, and training program procedures to determine if the exempted training items were covered in the licensed operator requalification training (LORT), and how training program changes would be handled in the future. In addition, Training Department personnel were interviewed to clarify what training expectations were and how the LORT program was managed. Documents reviewed are listed in the Attachment to this report.

b. Findings

No findings were identified. URI 05000266/2011004-01; 05000301/2011004-01, Potential Failure to Correctly Implement a Systems Approach to Training for the Licensed Operator Requalification Program, is closed.

1R12 Maintenance Effectiveness

.1 Routine Quarterly Evaluations

a. Inspection Scope

The inspectors evaluated degraded performance issues involving the following risk-significant systems:

• function-oriented approach for vital 120 Volt AC power;

• function-oriented approach for SW system;

• function-oriented approach for instrument air system;

• problem-oriented approach for electrohydraulic control (EHC) central system failures on Units 1 and 2 (partial);

• function-oriented approach for residual heat removal (RHR); and

• function-oriented approach for CCW system.

The inspectors reviewed events, such as where ineffective equipment maintenance had resulted in valid or invalid automatic actuations of engineered safeguards systems, and independently verified the licensee's actions to address system performance or condition problems in terms of the following:

• implementing appropriate work practices;

• identifying and addressing common cause failures;

• scoping of systems in accordance with 10 CFR 50.65(b) of the maintenance rule;

• characterizing system reliability issues for performance;

• charging unavailability for performance;

• trending key parameters for condition monitoring;

• ensuring 10 CFR 50.65(a)(1) or (a)(2) classification or re-classification; and

• verifying appropriate performance criteria for structures, systems, and components (SSCs)/functions classified as (a)(2), or appropriate and adequate goals and corrective actions for systems classified as (a)(1).

The inspectors assessed performance issues with respect to the reliability, availability, and condition monitoring of the system. In addition, the inspectors verified maintenance effectiveness issues were entered into the CAP with the appropriate significance characterization. Documents reviewed are listed in the Attachment to this report.

This inspection constituted five completed and one partial quarterly maintenance effectiveness samples as defined in IP 71111.12-05.

b. Findings

No findings were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

.1 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

The inspectors reviewed the licensee's evaluation and management of plant risk for the maintenance and emergent work activities affecting risk-significant and SR equipment listed below to verify that the appropriate risk assessments were performed prior to removing equipment for work during:

• high grid demand conditions and gas turbine (G-05) in manual with high vibrations;

• work management during the week of July 1, 2012;

• planned work and management decision-making during Red Alert condition;

• use of compensatory actions to maintain G-05 availability;

• placement of turbine EHCs in manual;

• pressurizer power-operated relief valves (PORVs) leaking and block valves isolated on Units 1 and 2; and

• EDG G-01 OOS and diesel-driven fire pump emergent failure the week of September 19, 2012.

These activities were selected based on their potential risk significance relative to the Reactor Safety Cornerstones. As applicable for each activity, the inspectors verified that risk assessments were performed as required by 10 CFR 50.65(a)(4) and were accurate and complete. When emergent work was performed, the inspectors verified that the plant risk was promptly reassessed and managed. The inspectors reviewed the scope of maintenance work, discussed the results of the assessment with the licensee's probabilistic risk analyst or shift technical advisor, and verified plant conditions were consistent with the risk assessment. The inspectors also reviewed TS requirements and walked down portions of redundant safety systems, when applicable, to verify risk analysis assumptions were valid and applicable requirements were met. Documents reviewed are listed in the Attachment to this report.

These maintenance risk assessments and emergent work control activities constituted seven samples as defined in IP 71111.13-05.

b. Findings

Failure to Implement Risk Management Actions During Various Emergent Work Activities

Introduction:

The inspectors identified a finding of very low safety significance (Green)and associated NCV of 10 CFR 50.65(a)(4) because the licensee failed to properly manage and assess risk for various emergent work activities.

Description:

During the third quarter inspection period, there were several instances identified by the inspectors where various OOS equipment was not included in the licensees daily online work risk assessment. The specific instances are described below:

• On July 12, 2012, the inspectors identified that G-05 was credited as available but nonfunctional in station logs and was not included in the licensees online work risk assessment for Units 1 and 2. The inspectors questioned the licensee about this classification as available but nonfunctional since in the previous week G-05 had twice tripped during startup, a condition engineering was continuing to evaluate and for which no cause had been identified. The licensee corrected the online risk model for the period from July 2, 2012 through July 12, 2012, in accordance with the procedure and found that this caused an increase in online risk. Because the licensee had been unaware that an increased risk condition existed, the licensee failed to assess and manage risk associated with this activity.

• On July 25, 2012, the inspectors identified that G-05 was placed on its turning gear for 15 minutes every 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />, and during that time was not included in the licensees online work risk assessment for Units 1 and 2. The inspectors questioned the licensee about the exclusion of this from the risk model due to inability to start G-05 from the control room during this period and the lack of dedicated operator in the field. The licensee corrected the online risk model for the period from July 19 through July 25, 2012, in accordance with the procedure and found that this caused an increase in online risk. Because the licensee had been unaware that an increased risk condition existed, the licensee failed to assess and manage risk associated with this activity.

• On August 21, 2012, the inspectors identified that the Unit 1 EHC system was placed in manual operation and was not included in the licensees online work risk assessment for Unit 1. The inspectors questioned the licensee about the exclusion of the EHC system in manual operation from the risk model due to the impact the manual operation had on the over-pressure delta temperature (OPT)and over-temperature delta temperature (OTT) runback features. The licensee corrected the online risk model for the period from August 20 through August 22, 2012, in accordance with the procedure and found that this caused an increase in online risk. Because the licensee had been unaware that an increased risk condition existed, the licensee failed to assess and manage risk associated with this activity.

The inspectors reviewed licensee procedure NP 10.3.7, On-Line Safety Assessment, and found that it outlined the requirements for performing safety assessments for equipment that is made or becomes unavailable on an operating unit. Specifically, NP 10.3.7, states that when a risk-significant SSC are made unavailable while a unit is at power, an assessment shall be performed to determine the overall effect of the planned or actual plant configuration on the level of safety of the plant. Further it states that the results of this assessment shall be used in plant decision making to manage the level, duration, and long term impact of safety decreases. In each instance, the inspectors determined that the licensee failed to properly assess and manage the increase in risk from the proposed maintenance activities in accordance with this procedure and with the maintenance rule. The inspectors concerns were entered into the licensees CAP as AR01808661.

Analysis:

The inspectors determined that the failure to properly manage and assess risk for various emergent work activities as described above was a violation of 10 CFR 50.65 and was a performance deficiency warranting further evaluation.

The finding was determined to be more than minor in accordance with IMC 0612, Appendix B, Issue Screening, in that the failure to properly manage and assess risk, if left uncorrected, would have the potential to become a more significant safety concern.

Specifically, the inspectors determined that the addition of a Unit 1 transient initiator and of G-05 modeled as OOS into the licensees safety monitor program for risk was more than minor because the licensees risk assessment was based on incorrect assumptions that changed the outcome of the assessment.

The inspectors evaluated the finding using IMC 0609, Attachment 0609.04, Tables 2 and 3, and Appendix K, Maintenance Risk Assessment And Risk Management Significance Determination Process, dated May 19, 2005. The inspectors determined that the finding was a mitigating systems contributor, evaluated the risk deficit for each instance, and found that the issue screened as having very low safety significance (Green). The issue was entered into the licensees corrective action program as action requests AR01808661 and AR01787706 for evaluation and development of corrective actions .

This finding has a cross-cutting aspect in the area of human performance, work practices, because the licensee failed to define and effectively communicate expectations regarding procedural compliance and ensure personnel follow procedures.

Specifically, in all instances the licensee failed to communicate expectations regarding compliance as required by procedure NP 1.1.4 and ensure personnel followed implementing procedure NP 10.3.7 for risk management (H.4(b)). The inspectors reviewed the licensees white paper discussion for the proposed cross-cutting aspect and found that the licensees assessment was consistent with the inspectors assessment of the condition.

Enforcement:

Title 10 CFR 50.65a(4) requires, in part, that before performing maintenance including, but not limited to surveillance, post-maintenance testing (PMT),and corrective and preventive maintenance, the licensee to properly assess and manage the increase in risk that may result from the proposed maintenance activities. Licensee procedure NP 10.3.7 outlines the requirements for performing safety assessments for equipment that is made or becomes unavailable on an operating unit.

Contrary to the above, on July 12, July 25, and August 21, 2012, the licensee failed to properly assess and manage the increase in risk associated with G-05 available but nonfunctional, G-05 unavailability when on the turning gear, and the Unit 1 turbine EHC system in manual. As a result, the licensees risk assessment was based on incorrect assumptions that changed the outcome of the assessment, and the appropriate risk management actions for this work activity were not implemented.

This violation is being treated as an NCV, consistent with Section 2.3.2 of the Enforcement Policy, because it was of very low safety significance (Green) and was entered into the CAP (as AR01787706 and AR01808661) to address recurrence (NCV 05000266/2012004-02; 05000301/2012004-02, Failure to Implement Risk Management Actions During Various Emergent Work Activities).

1R15 Operability Determinations and Functional Assessments

.1 Operability Evaluations

a. Inspection Scope

The inspectors reviewed the following operability issues:

• water leaking in steam generator (SG) vault A (Unit 2);

• operability of TDAFW failed coupling (Unit 1);

• boric acid on valve 2SC-955 may interfere with limit switches (Unit 2);

• operability of G-02 with dampers partially blocked (Units 1 and 2);

• operability evaluation of PORVs leakage (Unit 2); and

• functionality assessment of turbine EHC in manual (Unit 1).

The inspectors selected these potential operability/functionality issues based on the risk significance of the associated components and systems. The inspectors evaluated the technical adequacy of the evaluations to ensure that TS operability was properly justified and the subject component or system remained available such that no unrecognized increase in risk occurred. The inspectors compared the operability and design criteria in the appropriate sections of the TSs and FSAR to the licensees evaluations to determine whether the components or systems were operable. Where compensatory measures were required to maintain operability, the inspectors determined whether the measures in place would function as intended and were properly controlled. The inspectors determined, where appropriate, compliance with bounding limitations associated with the evaluations. Additionally, the inspectors reviewed a sampling of corrective action documents to verify that the licensee was identifying and correcting any deficiencies associated with operability evaluations. Documents reviewed are listed in the to this report.

This operability inspection constituted six samples as defined in IP 71111.15-05.

b. Findings

Plant Operation with an Unacceptable ASME Code Class 2 Pressure Boundary Flaw

Introduction:

The inspectors identified a finding of very low safety significance (Green)and associated NCV of 10 CFR 50.55a(g)(4) because the licensee failed to identify and evaluate an American Society of Mechanical Engineers (ASME) Code Class pressure boundary leak in the Unit 2 containment.

Description:

On May 10, 2012, the licensee initiated AR01765732, U2 Sump A Drain Frequency is Increasing, to assess potential leakage into the Unit 2 containment.

The CR noted that the leakage exceeded the calculated reactor coolant system (RCS)leak rate, and an evaluation was performed to address the leakage source. The CR reasonably concluded that the leakage source was from the steam generation and delivery system (SG, FW, or main steam). This conclusion was based on primary leakage rate calculations and chemistry samples of the water being collected combined with an assessment of component cooling makeup water trends. The CR also indicated that a visual inspection determined the leak was very small, 20 to 30 drops-per-minute, and was located inside the Unit 2 SG A vault. Throughout the period of leakage, the inspectors continued to monitor and assess any changes in the leak rate to determine if the licensees corrective actions were commensurate with risk and safety.

The licensee completed a prompt operability determination (POD) for AR01765732, Revision 0, on May 22, 2012, and concluded that it was mechanical joint leakage. Since the licensee could not identify the leakage source, it could not be determined if the leak was from an ASME Code component. Many of the components in the area of the leak were in the ASME Code Class 2 boundary, and most likely met the definition of high energy: >200 degrees Fahrenheit (°F) and >275 pounds per square inch gauge (psig).

Because many of the components in the susceptible location were ASME Code components, the inspectors reviewed the requirements and expectations related to Code pressure boundary leakage.

The NRC does not consider through-wall leakage from components, as opposed to leakage from mechanical joints, to be in accordance with the intent of the ASME Code or construction code, and therefore, would not meet code requirements, even though the system or component may demonstrate adequate structural integrity. When ASME components do not meet ASME Code or construction code acceptance standards, the requirements of an NRC-endorsed ASME Code case, or an NRC-approved alternative, then a licensee must determine whether the degraded or nonconforming condition results in a TS-required SSC or a TS-required support SSC being inoperable. Upon discovery of leakage from a TS-required Class 2 or Class 3 component, the component must be evaluated in an immediate operability determination (followed by a POD) if additional or supporting analysis is needed to support a reasonable expectation of operability. In performing the immediate determination, the degradation mechanism would have to be readily apparent to support a determination of operable. To be readily apparent, the degradation mechanism must be discernable from visual inspection (such as external corrosion or wear) or substantial operating experience must exist with the degradation mechanism on the system at the facility. As outlined under defined terms of Part 9900 Technical Guidance, Operability Determinations & Functionality Assessments for Resolution of Degraded or Nonconforming Conditions Adverse to Quality or Safety, Section 3.9, Reasonable Expectation, there is no such thing as an indeterminate state of operability; an SSC is either operable or inoperable.

Between May 22 and June 19, 2012, the inspectors continued to inquire about the source of the leakage. On June 20, 2012, the licensee issued Revision 1 to the POD, AR01765732. The revision stated that the source was unknown, and attempted to establish reasonable assurance that the leakage was from a mechanical joint using alternate methods and logical arguments. The inspectors concluded that the indirect methods used to make the conclusion that the leakage was from a mechanical joint were limited given the large number of potential sources of leakage that could exist within the SG vault, narrowly focused, not based on extensive site operating experience and, therefore, did not adequately support operability. In addition, the evaluation contained inconsistencies that raised further questions about the adequacy of the evaluation.

Further, throughout the duration of the leakage assessments, the licensee emphasized that identification of the leakage would be hard because the area requiring inspection was a high-temperature and high radiation zone and that related inspections would be impractical without a power reduction or unit shutdown; however, the licensee was examining alternate methods to assess the source of leakage. The inspectors were concerned that: the operability evaluation did not provide adequate justification for not identifying the leakage source; the operability evaluation did not develop supporting arguments that gave reasonable assurance that the source of the leakage was from a mechanical joint; the leakage complied with ASME Code criteria; that the leakage rate was slowly increasing; and, that progression towards identifying an alternate method to determine the leakage source was not risk-informed or factored in the related limited condition for operation (LCO) completion times as guidance for completing the POD.

On June 27, 2012, the Unit 2 reactor tripped due to an unrelated turbine control system malfunction. This unplanned shutdown provided an opportunity for the licensee to inspect the affected SG vault. The leak was determined to be coming from a weld on an un-isolable section of 3/4-inch diameter blowdown piping on the Unit 2 SG A, an ASME Code Class 2 High Energy pipe. Because this through-wall condition would not meet ASME Code or construction code acceptance standards, or could be accepted by an NRC-endorsed ASME Code case, Unit 2 was taken to cold shutdown. The pipe was repaired by replacing the affected pipe section in accordance with ASME Code requirements, and was quarantined for future analysis. The issue was entered into the licensees CAP as action requests AR01789202 and AR01797798 for evaluation and development of further corrective actions. Actions taken to address recurrence of the issue included performance of an apparent cause evaluation (ACE), information sharing to engineering and operations, and fleet review of the procedure to identify gaps and enhancements as a result of this condition.

Analysis:

The inspectors determined that the licensees failure to follow the ASME Code requirements for evaluating the leak in the Unit 2 containment was a violation and was a performance deficiency warranting further review.

The finding was determined to be more than minor in accordance with IMC 0612, Appendix B, Issue Screening, because it was associated with the Initiating Events Cornerstone attribute of equipment performance, and adversely affected the reliability of the steam generation systems (SG, FW, or main steam); thereby, directly impacting the cornerstone objective to limit the likelihood of events that upset plant stability during power operations. Specifically, the inspectors determined that in addition to being a potential transient initiator, the potential failure location affected both the containment barrier during a loss of coolant accident (LOCA) and the reactor pressure system boundary during an SG tube failure event.

The inspectors evaluated the finding using IMC 0609, Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings, Tables 2 and 3, dated June 19, 2012, and Appendix A, The Significance Determination Process (SDP)for Findings At-Power, Exhibit 1 for the Initiating Events Cornerstone, dated June 19, 2012. The inspectors answered No to the Exhibit 1 questions in Appendix A for transient initiators and support system initiators. Therefore, the inspectors determined the finding to be of very low safety significance (Green).

This finding has a cross-cutting aspect in the area of human performance, conservative assumptions. Specifically, the licensee failed to use conservative assumptions in decision-making because it developed an operability evaluation demonstrating that continued full power operation was acceptable without reasonable assurance that the leakage was from a mechanical joint, rather than developing reasonable assurance or providing physical evidence, either indirectly or by observation, that the leakage was not pressure boundary leakage (H.1(b)).

Enforcement:

Title 10 CFR 50.55a(g)(4) states that, Throughout the service life of a boiling or pressurized water reactor cooled nuclear power facility, components (including supports) which are classified as ASME Code Class 1, Class 2 and Class 3 must meet the requirements, except design and access provision and preservice examination requirements, set forth in Section XI of editions of the ASME Boiler and Pressure Vessel Code and Addenda that become effective subsequent to editions specified in paragraphs (g)(2) and (g)(3) of this section and are incorporated by reference in paragraph

(b) of this section, to the extend practical within the limitations of design, geometry and materials of construction of the components.

Contrary to the above requirements, between May 22 and June 26, 2012, the licensee did not identify that the through-wall leakage from an unknown source was from the pressure boundary of an ASME Code Class 2, high energy component required to comply with 10 CFR 50.55a(g)(4). Specifically, the through-wall leak on a Unit 2 SG A blowdown line weld, an ASME Section XI component, did not meet the ASME Code Section XI criteria required by this regulation. The regulation requires that unacceptable ASME Code components be repaired in accordance with the Code; their structural integrity be accepted through analysis of approved Code cases or relief requested from the Code requirements; and approved by the NRC. In this case, the licensee took none of these actions, and the plant continued to operate with an unknown source of leakage based on an incorrect operability evaluation.

This violation is being treated as an NCV, consistent with Section 2.3.2 of the Enforcement Policy, because it was of very low safety significance (Green) and was entered into the CAP as (AR1797798 and AR1789202) to address recurrence.

(NCV 05000301/2012004-03, Plant Operation with an Unacceptable ASME Code Class 2 Pressure Boundary Flaw).

1R18 Plant Modifications

The inspectors reviewed the following modifications:

• EDG exhaust stack temporary structure (temporary).

The inspectors reviewed the configuration changes and associated 10 CFR 50.59 safety evaluation screening against the design basis, the FSAR, and the TSs, as applicable, to verify that the modification did not affect the operability or availability of the affected systems. The inspectors, as applicable, observed ongoing and completed work activities to ensure that the modifications were installed as directed and consistent with the design control documents; the modifications operated as expected; post-modification testing adequately demonstrated continued system operability, availability, and reliability; and that operation of the modifications did not impact the operability of any interfacing systems. As applicable, the inspectors verified that relevant procedure, design, and licensing documents were properly updated. Lastly, the inspectors discussed the plant modification with operations, engineering, and training personnel to ensure that the individuals were aware of how the operation with the plant modification in place could impact overall plant performance. Documents reviewed are listed in the Attachment to this report.

This inspection constituted one temporary modification sample as defined in IP 71111.18 05.

b. Findings

Weld Design Deficiency in Emergency Diesel Generator Missile Protection Barriers

Introduction:

The inspectors identified a finding of very low safety significance (Green)and associated NCV of 10 CFR Part 50, Appendix B, Criterion III, Design Control, because the licensee failed to identify a deficiency in weld evaluations in the design calculation of the new missile protection steel barriers for EDGs.

Description:

As part of corrective actions resulting from a previous NRC finding for failure to ensure tornado missile protection for EDGs G-01 and G-02 exhaust stacks (NCV 05000266/2011004-03, 05000301/2011004-03), the licensee installed new steel barrier plates for protection of the EDG exhaust pipes using a temporary modification (TMOD). During review of the structural design calculation S-11165-194-01, the inspectors identified two examples where welds critical for the integrity of the structure were not adequately addressed in the calculation. The first example involved design of the missile barrier plates for protection of the vertical sections of the exhaust pipes from an automobile missile. The inspectors identified that the three supporting horizontal structural tube steel members were assumed to be continuous in the design despite having only partially effective welded connection at mid span which was the critical stress location. The licensee subsequently revised the design adding seven additional continuous steel tube sections. The second example involved the design of barrier plates installed on the west side of shipping containers used in the TMOD. The licensee did not perform a detailed evaluation of the weld on the tube steel members supporting the barrier plates, indicating that they were considered adequate by engineering judgment. During review in response to the inspectors questions, the licensee found that the welds were not adequate and additionally, there were discrepancies between the design and installed configurations. The licensee then redesigned and reinforced the welds. Subsequently, the licensee performed more refined finite element analyses to determine operability/functionality during the period between the TMOD completion date of May 2, 2012, and the corrective action completion date of June 5, 2012. The analyses indicated that missile protective structures with the welding deficiencies noted in the above two examples, while undergoing large plastic deformations, would have been able to prevent any impact between the EDG stacks and the barrier plates or the postulated missiles, thus maintaining operability of the EDGs. The design deficiencies were captured in the licensee CAP as AR01771762 and AR01772431. During an extent of condition walkdown of the TMOD installation in response to the inspection-identified discrepancies, the licensee identified another as-built discrepancy where a stack of steel plates designed to spread out the loads from a new barrier support post over a larger area for evaluation of buried electrical duct bank were not installed in field. This condition was identified in AR01773042, and plates were installed in field to conform to design.

Analysis:

The inspectors determined that in the first example, an assumption that the welds provided full continuity of structural sections, was contrary to the weld configuration shown in the design drawing, and in the second example the engineering judgment regarding the weld being acceptable was found to be inaccurate based on subsequent evaluations. The inspectors, therefore, determined that the examples constituted a performance deficiency, because the modification was not installed as designed, nor the discrepancies with installation appropriately dispositioned.

The inspectors determined that the finding was more than minor in accordance with IMC 0612, Appendix B, and used Appendix E, Example of Minor Issues, dated August 11, 2009, and found that it was similar to Example 3a and affected the Mitigating Systems Cornerstone. The TMOD was installed to provide tornado missile protection for the EDG exhaust pipes and the calculation was intended to demonstrate structural adequacy of the barrier plates. The calculation deficiency was significant enough to require field modifications and calculation revisions in both the examples. By the end of the inspection, through more refined finite element analysis, the licensee was able to demonstrate that the barrier plates would have remained functional and would have provided missile protection to maintain operability of the EDGs. However, at the time of discovery, there was a reasonable doubt regarding their ability to do so. Therefore, this performance deficiency also impacted the Mitigating Systems Cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences.

The inspectors evaluated the finding using IMC 0609, Attachment 0609.04, Tables 2 and 3, and Appendix A, Exhibit 1 for the Mitigating Systems Cornerstone, dated June 19, 2012. The inspectors answered Yes to Exhibit 2, Question A.1 in Appendix A for mitigating SSCs, and functionality. Specifically, since the barrier plates would have been able to prevent a missile impact with the EDG stacks, the operability of the EDGs would not have been affected. Therefore, the inspectors determined the finding to be of very low safety significance (Green).

This finding has a cross-cutting aspect in the area of human performance, work practices, because the licensee failed to ensure supervisory oversight of the contractor activities to support nuclear safety. Specifically, in the examples noted, the licensee failed to adequately review the calculation performed by the contractor to verify that the assumptions and engineering judgments were consistent with the installation and adequately justified (H.4(c)).

Enforcement:

Title 10 CFR Part 50, Appendix B, Criterion III, Design Control, requires, in part, that design control measures provide for verifying or checking the adequacy of design, such as by the performance of design reviews, by the use of alternate or simplified calculational methods, or by the performance of a suitable testing program.

Contrary to the above, on April 30, 2012, in the design calculation S-11165-194-01, Revision 3, the licensee failed to verify adequacy of the assumptions and engineering judgments used in the design of temporary DG tornado missile barriers. Specifically, the design calculation incorrectly assumed continuity of the cross section of framing structural members while the installation detail indicated a significantly weaker section at the existing welded joint. In addition, the licensee calculation accepted some welds based on engineering judgment that on detailed review was found to be unjustified.

This violation is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy, because it was of very low safety significance and was entered into the licensees CAP (as AR01771762 and AR01772431) to address recurrence (NCV 05000266/2012004-04; 05000301/2012004-04, Weld Design Deficiency in Emergency Diesel Generator Missile Protection Barriers).

1R19 Post-Maintenance Testing

.1 Post-Maintenance Testing (PMT)

a. Inspection Scope

The inspectors reviewed the following post-maintenance activities to verify that procedures and test activities were adequate to ensure system operability and functional capability:

• PMT of P-32B (SW) following pump replacement (Units 1 and 2);

• PMT of 1P-11B (CCW) pump following breaker maintenance (Unit 1);

• PMT of primary auxiliary building (PAB) ventilation system following damper maintenance (Units 1 and 2);

• PMT of 2SI-850A following failed stroke testing and limitorque switches maintenance (Unit 2);

• PMT following over-temperature delta temperature (OTT) channel failure due to lead/lag box failure (Unit 2);

• PMT of EDG G-01 following overhaul annual maintenance (Units 1 and 2); and

• PMT of diesel-driven fire pump P-38B following maintenance (Units 1 and 2);

These activities were selected based upon the SSCs ability to impact risk. The inspectors evaluated these activities for the following (as applicable): the effect of testing on the plant had been adequately addressed; testing was adequate for the maintenance performed; acceptance criteria were clear and demonstrated operational readiness; test instrumentation was appropriate; tests were performed as written in accordance with properly reviewed and approved procedures; equipment was returned to its operational status following testing (TMODs or jumpers required for test performance were properly removed after test completion); and test documentation was properly evaluated. The inspectors evaluated the activities against TSs, the FSAR, 10 CFR Part 50 requirements, licensee procedures, and various NRC generic communications to ensure that the test results adequately ensured that the equipment met the licensing basis and design requirements. In addition, the inspectors reviewed corrective action documents associated with PMTs to determine whether the licensee was identifying problems and entering them in the CAP and that the problems were being corrected commensurate with their importance to safety. Documents reviewed are listed in the Attachment to this report.

This inspection constituted seven post-maintenance testing samples as defined in IP 71111.19-05.

b. Findings

No findings were identified.

1R20 Outage Activities

.1 Other Outage Activities

a. Inspection Scope

The inspectors evaluated Unit 2 outage activities for an unplanned outage that began on June 27, 2012, and continued through July 2, 2012. The outage occurred as a result of a turbine control system malfunction that resulted in a turbine load reject, which terminated when the reactor operators inserted a manual reactor trip. The inspectors reviewed activities to ensure that the licensee considered risk in developing, planning, and implementing the outage schedule.

The inspectors observed or reviewed the outage equipment configuration and risk management, electrical lineups, selected clearances, control and monitoring of decay heat removal, control of containment activities, personnel fatigue management, startup and heatup activities, and identification and resolution of problems associated with the outage.

This inspection constituted one outage sample as defined in IP 71111.20-05.

a. Findings

(1) Boric Acid Not Removed from Containment Isolation Valve as Required by Procedure

Introduction:

The inspectors identified a finding of very low safety significance (Green)and associated NCV of 10 CFR Part 50, Appendix B, Criterion V, for the licensees failure to clean boric acid from RCS hot leg sample isolation valve 2SC-955.

Description:

The Boric Acid Leakage and Corrosion Monitoring [BALCM] Program, Revision 7, Step 4.2.4, requires that accessible areas of containment be entered during forced outages when at least 30 days have elapsed since startup. On June 28, 2012, during the Unit 2-required containment walkdown performed for the unplanned outage, the licensee and the inspectors independently identified boric acid leakage by the packing of the RCS hot leg sample isolation valve 2SC-955. The inspectors concluded that the leak was active and the accumulation was significant, potentially interfering with the valve position limit switches. The inspectors assessment was independently corroborated by the licensee, as documented on the related boric acid screening and evaluation forms.

Because valve 2SC-955 was a seismic Class 1, safety-related, containment isolation valve (CIV), the inspectors reviewed the issue and associated corrective actions further.

The inspectors identified that BALCM Program, Step 4.3, and Appendix C, Steps 2.9.2 and 2.9.5, required that all boric acid leakage be cleaned, and be categorized as clean only. The inspectors identified that the licensee had failed to enter this component into the outage work plan to ensure that the issue was dispositioned and the valve cleaned prior to the unit returning to service. The inspectors reviewed the position limit switch functions and procedures that credited the switches, and found that the switches did not provide input into any automatic functions or interlocks. However, licensed operators utilized the valve position information provided by the switches to verify containment isolation during certain transients and accidents. An impairment could complicate operator response during conditions that result in a valid containment isolation signal.

As a result of the inspectors inquiries, the valve was entered into the work plan and cleaned prior to unit restart. The licensee initiated AR01782290, Boric Acid Clean List Not Sent to RP [radiation protection], to evaluate the missed maintenance activity.

Additional corrective actions were initiated as AR01765986, AR01780951, and AR0179802 to address recurrence and included a modification to the containment walkdown repetitive maintenance tasks to include a step to provide the cleaning list to RP, and the performance of an ACE, which was anticipated to identify additional areas for improvement.

Analysis:

The inspectors determined that the failure to enter valve 2SC-955 into the outage work plan for cleaning was a violation of procedure and a performance deficiency warranting further review. The finding was determined to be more than minor in accordance with IMC 0612, Appendix B, Issue Screening, because it was associated with the Barrier Integrity Cornerstone attribute of RCS equipment and barrier performance and adversely affected the cornerstone objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. Additionally, if left uncorrected, it could impact the operators ability to verify a containment isolation actuation, thereby adversely affecting the cornerstone objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events.

Specifically, the inspectors determined that if left uncorrected, the boric acid mound would have grown and possibly encased the related valve position limit switches, binding them and rendering the switches inoperable.

The inspectors evaluated the finding using IMC 0609, Attachment 0609.04, Tables 2 and 3, and Appendix A, Exhibit 2 for the the Mitigating Systems Cornerstone. The inspectors answered Yes to Exhibit 2, Question A.1 in Appendix A for mitigating SSCs and functionality. The inspectors determined that the issue was a design or qualification deficiency confirmed not to result in a loss of operability. Therefore, inspectors determined the finding to be of very low safety significance (Green).

This finding has a cross-cutting aspect in the area of human performance, systematic processes, because the licensee failed to use a systematic process when making decisions related to the cleaning of the boric acid components during the unplanned shutdown. Specifically, the licensees communications and interfaces for performing the activities and developing corrective actions were not approached rigorously and systematically when the duration of the unplanned outage was significantly shortened and plant startup timelines modified the expected boric acid cleaning plans (H.1(a)).

Enforcement:

Title 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, requires that activities affecting quality be prescribed by procedures of a type appropriate to the circumstances and be accomplished in accordance with these procedures. The inspectors found that the safety-related RCS hot leg sample isolation valve 2SC-955 was subject to the requirements of 10 CFR Part 50, Appendix B, and that proper implementation of the BALCM Program supports the operability of this valve and supporting systems. The licensees BALCM Program had multiple steps that required that the boric acid be cleaned and the leak be evaluated. BALCM Program, Step 4.3 and Appendix C, Steps 2.9.2 and 2.9.5 required that all boric acid indications be cleaned, and be categorized as clean only. Contrary to this, on July 1, 2012, the licensee did not clean an accumulation of boric acid from an active leak on valve 2SC-955, an activity affecting the quality of an Appendix B component and its related support systems.

This violation is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy, because it was of very low safety significance and was entered into the licensees CAP as (AR01782290, AR01765986, AR01780951, and AR01797802) to address recurrence (NCV 05000301/2012004-05, Boric Acid Not Removed From Containment Isolation Valve as Required by Procedure).

(2) Foreign Material Not Removed from Containment Prior to Reactor Restart as Required by Procedure

Introduction:

The inspectors identified a finding of very low safety significance (Green)and associated NCV of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the licensees failure to remove a plastic bag of transient materials that could interact with the Unit 2 containment sump recirculation strainer.

Description:

On July 2, 2012, subsequent to the licensee indicating that the Unit 2 containment closure was completed and prior to reactor startup, the inspectors performed a containment closure inspection and identified a plastic trash bag of foreign material containing cleaning materials and mop heads that had not been removed from the containment. The inspectors determined that the material could have a negative impact on the containment recirculation sump (sump B) and should have been removed, by procedure.

The inspectors reviewed procedures CL 20, Post Outage Containment Closeout Checklist, and MA-AA-101-1000, Foreign Material Exclusion Procedure, as well as related condition evaluations, and concluded that CL 20 was applicable to this activity.

The inspectors found that the purpose of CL 20 was, to ensure that no materials are left in the reactor containment that, in the unlikely event of an accident which requires Sump B recirculation, would block the suction path of the low head safety injection pumps. Additionally, Step 5.1 required documenting all discrepancies for disposition including temporary materials to be removed. The licensee indicated that the materials were used in the cleaning boron from valve 2SC-955 and were not removed subsequent to the activity (Section 1R20.1(1)).

The licensee performed an evaluation of the materials and determined that the volume of material did not exceed the margin available for transient materials. The licensee entered this issue into the CAP as AR01781331, Items Inside U2 Containment, NRC Walkdown, to evaluate the issue. Compliance was immediately restored when the licensee removed the materials from containment. Additional corrective actions were initiated under AR01808631, to address recurrence, and included a procedural modification for the licensee to perform an independent closeout walk down as an independent verification that containment closure activities were successfully performed.

Analysis:

The inspectors determined that the failure to document and remove a bag of temporary materials used for cleaning of valve 2SC-955 as required by procedure CL 20 was a performance deficiency warranting further review. The finding was determined to be more than minor in accordance with IMC 0612, Appendix B, Issue Screening, because it was associated with the Mitigating System Cornerstone attribute of equipment performance and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. In this instance, low head safety injection (SI)system availability and reliability could be reduced by the introduction of temporary material into the containment that could interact and reduce the available area on the recirculation sump suction strainer.

The inspectors evaluated the finding using IMC 0609, Attachment 0609.04, Tables 2 and 3, and Appendix A, Exhibit 2 for the Mitigating Systems Cornerstone. The inspectors answered Yes to Exhibit 2, Question A.1 in Appendix A for mitigating structures, systems, and components, and functionality. Therefore, inspectors determined the finding to be of very low safety significance (Green).

The finding did not have a cross-cutting aspect because the cause of the issue was identical to the cause for the boric acid not being removed from CIV 2SC-955, as required by procedure and the cross-cutting aspect was captured prior by that issue (Section 1R20.1(1)).

Enforcement:

Title 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, requires that activities affecting quality be prescribed by procedures of a type appropriate to the circumstances and shall be accomplished in accordance with these procedures.

On July 2, 2012, contrary to the requirements of procedure CL 20, Post Outage Containment Closeout Inspection, Step 5.1, temporary materials that impacted the qualification of the containment recirculation sump were left inside the containment.

This violation is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy because it was of very low safety significance and was entered into the licensees CAP as (AR01781331 and AR01808631) to address recurrence (NCV 05000301/2012004-06, Transient Materials Not Removed from Containment Prior to Reactor Startup).

.2 Other Outage Activities

a. Inspection Scope

The inspectors evaluated Unit 1 outage activities for an unplanned outage that began on August 14, 2012, and continued through August 19, 2012. The outage occurred as a result of a turbine control system malfunction that resulted in a turbine load reject which terminated when the reactor operators inserted a manual reactor trip. The inspectors reviewed activities to ensure that the licensee considered risk in developing, planning, and implementing the schedule for the resulting outage.

The inspectors observed or reviewed the reactor shutdown and cooldown, outage equipment configuration and risk management, electrical lineups, selected clearances, control and monitoring of decay heat removal, control of containment activities, startup and heatup activities, and identification and resolution of problems associated with the outage.

This inspection constituted one outage sample as defined in IP 71111.20-05.

b. Findings

No findings were identified.

1R22 Surveillance Testing

.1 Surveillance Testing

a. Inspection Scope

The inspectors reviewed the test results for the following activities to determine whether risk-significant systems and equipment were capable of performing their intended safety function and to verify testing was conducted in accordance with applicable procedural and TS requirements:

• Unit 2 ECCS safeguards system venting (routine);

• Unit 2 train A SI valve quarterly surveillance (routine);

• Unit 2 motor-driven auxiliary feedwater (AFW) pump quarterly surveillance (routine);

• Unit 1 atmospheric steam dump valve surveillance (routine);

• Unit 1 reactor protection system (RPS) and safeguard white channel analog surveillance (routine);

• Unit 2 RCS valve quarterly surveillance (inservice testing (IST));

• Unit 2 containment radiation monitor surveillance (RCS);

• EDG G-02 monthly surveillance (routine); and

• Unit 2 containment accident fan coil unit monthly surveillance (routine).

The inspectors observed in-plant activities and reviewed procedures and associated records to determine the following:

• did preconditioning occur;

• the effects of the testing were adequately addressed by control room personnel or engineers prior to the commencement of the testing;

• acceptance criteria were clearly stated, demonstrated operational readiness, and consistent with the system design basis;

• plant equipment calibration was correct, accurate, and properly documented;

• as-left setpoints were within required ranges; and the calibration frequency was in accordance with TSs, the FSAR, procedures, and applicable commitments;

• measuring and test equipment calibration was current;

• test equipment was used within the required range and accuracy; applicable prerequisites described in the test procedures were satisfied;

• test frequencies met TS requirements to demonstrate operability and reliability; tests were performed in accordance with the test procedures and other applicable procedures; jumpers and lifted leads were controlled and restored where used;

• test data and results were accurate, complete, within limits, and valid;

• test equipment was removed after testing;

• where applicable for inservice testing activities, testing was performed in accordance with the applicable version of ASME Code,Section XI, and reference values were consistent with the system design basis;

• where applicable, test results not meeting acceptance criteria were addressed with an adequate operability evaluation or the system or component was declared inoperable;

• where applicable for safety-related instrument control surveillance tests, reference setting data were accurately incorporated in the test procedure;

• where applicable, actual conditions encountering high resistance electrical contacts were such that the intended safety function could still be accomplished;

• prior procedure changes had not provided an opportunity to identify problems encountered during the performance of the surveillance or calibration test;

• equipment was returned to a position or status required to support the performance of its safety functions; and

• all problems identified during the testing were appropriately documented and dispositioned in the CAP.

Documents reviewed are listed in the Attachment to this report.

This inspection constituted seven routine surveillance testing samples, one inservice testing sample, and one reactor coolant system leak detection inspection sample, as defined in IP 71111.22, Sections -02 and -05.

b. Findings

No findings were identified.

OTHER ACTIVITIES

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, and Emergency Preparedness

4OA1 Performance Indicator Verification

.1 Mitigating Systems Performance Index - Emergency AC Power Systems

a. Inspection Scope

The inspectors sampled licensee submittals for the Mitigating Systems Performance Index (MSPI) - Emergency AC Power Systems performance indicator (PI) for Units 1 and 2, for the third quarter 2011 through the second quarter 2012. To determine the accuracy of the PI data reported, PI definitions and guidance contained in the Nuclear Energy Institute (NEI) Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, dated October 2009, were used. The inspectors reviewed the licensees operator narrative logs, MSPI derivation reports, CRs, event reports, and NRC integrated Inspection Reports (IRs) to validate the accuracy of the submittals. The inspectors reviewed the MSPI component risk coefficient to determine if it had changed by more than 25 percent since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance. The inspectors also reviewed the licensees CAP to determine if any problems had been identified with the PI data collected or transmitted for this indicator and none were identified. Documents reviewed are listed in the Attachment to this report.

This inspection constituted two MSPI emergency AC power system samples as defined in IP 71151-05.

b. Findings

No findings were identified.

.2 Mitigating Systems Performance Index - High Pressure Injection Systems

a. Inspection Scope

The inspectors sampled licensee submittals for the MSPI - High Pressure Injection Systems PI for Units 1 and 2 for the third quarter 2011 through the second quarter 2012.

To determine the accuracy of the PI data reported, PI definitions and guidance contained in the NEI 99-02 were used. The inspectors reviewed the licensees operator narrative logs, CRs, MSPI derivation reports, event reports, and NRC integrated IRs to validate the accuracy of the submittals. The inspectors reviewed the MSPI component risk coefficient to determine if it had changed by more than 25 percent since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance.

The inspectors also reviewed the licensees CAP to determine if any problems had been identified with the PI data collected or transmitted for this indicator and none were identified. Documents reviewed are listed in the Attachment to this report.

This inspection constituted two MSPI high pressure injection system samples as defined in IP 71151-05.

b. Findings

No findings were identified.

.3 Mitigating Systems Performance Index - Heat Removal Systems

a. Inspection Scope

The inspectors sampled licensee submittals for the MSPI - Heat Removal Systems PI for Units 1 and 2 for the third quarter 2011 through the second quarter 2012. To determine the accuracy of the PI data, PI definitions and guidance contained in NEI 99-02 were used. The inspectors reviewed the licensees operator narrative logs, CRs, event reports, MSPI derivation reports, and NRC integrated IRs to validate the accuracy of the submittals. The inspectors reviewed the MSPI component risk coefficient to determine if it had changed by more than 25 percent since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance. The inspectors also reviewed the licensees CAP to determine if any problems had been identified with the PI data collected or transmitted for this indicator and none were identified. Documents reviewed are listed in the Attachment to this report.

This inspection constituted two MSPI heat removal system samples as defined in IP 71151-05.

b. Findings

No findings were identified.

.4 Mitigating Systems Performance Index - Residual Heat Removal Systems

a. Inspection Scope

The inspectors sampled licensee submittals for the MSPI - Residual Heat Removal Systems PI for Units 1 and 2, for the third quarter 2011 through the second quarter 2012. To determine the accuracy of the PI data reported, PI definitions and guidance contained in the NEI 99-02 were used. The inspectors reviewed the licensees operator narrative logs, CRs, MSPI derivation reports, event reports, and NRC integrated IRs to validate the accuracy of the submittals. The inspectors reviewed the MSPI component risk coefficient to determine if it had changed by more than 25 percent since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance. The inspectors also reviewed the licensees CAP to determine if any problems had been identified with the PI data collected or transmitted for this indicator and none were identified. Documents reviewed are listed in the Attachment to this report.

This inspection constituted two MSPI residual heat removal system samples as defined in IP 71151-05.

b. Findings

No findings were identified.

.5 Mitigating Systems Performance Index - Support Cooling Water Systems

a. Inspection Scope

The inspectors sampled licensee submittals for the MSPI - Support Cooling Water Systems PI for Units 1 and 2, for the third quarter 2011 through the second quarter 2012. To determine the accuracy of the PI data reported, PI definitions and guidance contained in the NEI 99-02 were used. The inspectors reviewed the licensees operator narrative logs, CRs, MSPI derivation reports, event reports, and NRC integrated IRs to validate the accuracy of the submittals. The inspectors reviewed the MSPI component risk coefficient to determine if it had changed by more than 25 percent since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance. The inspectors also reviewed the licensees CAP to determine if any problems had been identified with the PI data collected or transmitted for this indicator and none were identified. Documents reviewed are listed in the Attachment to this report.

This inspection constituted two MSPI cooling water system sample as defined in IP 71151-05.

b. Findings

No findings were identified.

4OA2 Problem Identification and Resolution

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, Emergency Preparedness, Public Radiation Safety, Occupational Radiation Safety, and Physical Protection

.1 Routine Review of Items Entered into the Corrective Action Program

a. Inspection Scope

As part of the various baseline inspection procedures discussed in previous sections of this report, the inspectors routinely reviewed issues during baseline inspection activities and plant status reviews to verify that they were being entered into the licensees CAP at an appropriate threshold, that adequate attention was being given to timely corrective actions, and that adverse trends were identified and addressed. Attributes reviewed included: identification of the problem was complete and accurate; timeliness was commensurate with the safety significance; evaluation and disposition of performance issues, generic implications, common causes, contributing factors, root causes, extent-of-condition reviews, and previous occurrences reviews were proper and adequate; and that the classification, prioritization, focus, and timeliness of corrective actions were commensurate with safety and sufficient to prevent recurrence of the issue.

Minor issues entered into the licensees CAP as a result of the inspectors observations are included in the Attachment to this report.

These routine reviews for the identification and resolution of problems did not constitute any additional inspection samples. Instead, by procedure they were considered an integral part of the inspections performed during the quarter and documented in Section 1 of this report.

b. Findings

No findings were identified.

.2 Daily Corrective Action Program Reviews

a. Inspection Scope

In order to assist with the identification of repetitive equipment failures and specific human performance issues for follow-up, the inspectors performed a daily screening of items entered into the licensees CAP. This review was accomplished through inspection of the stations daily condition report packages.

These daily reviews were performed by procedure as part of the inspectors daily plant status monitoring activities and, as such, did not constitute any separate inspection samples.

b. Findings

No findings were identified.

.3 Semi-Annual Trend Review

a. Inspection Scope

The inspectors performed a review of the licensees CAP and associated documents to identify trends that could indicate the existence of a more significant safety issue. The inspectors review was focused on repetitive equipment issues, but also considered the results of daily inspector CAP item screening discussed in Section 4OA2.2 above, licensee trending efforts, and licensee human performance results. The inspectors review nominally considered the 6-month period of March 2012 through September 2012, although some examples expanded beyond those dates where the scope of the trend warranted.

The review also included issues documented outside the normal CAP in major equipment problem lists, repetitive and/or rework maintenance lists, departmental problem/challenges lists, system health reports, quality assurance audit/surveillance reports, self-assessment reports, and Maintenance Rule assessments. The inspectors compared and contrasted their results with the results contained in the licensees CAP trending reports. Corrective actions associated with a sample of the issues identified in the licensees trending reports were reviewed for adequacy.

This review constituted one semi-annual trend inspection sample as defined in IP 71152-05.

b. Findings

No findings were identified.

.4 Selected Issue Follow-Up Inspection: Reporting of PI Data

a. Inspection Scope

The inspectors reviewed items entered in the licensees CAP and noted that corrective action items were not generated on several occasions for issues identified by inspectors regarding the licensees submittal of RCS leak rate PI data. The inspectors elected to review this practice as a selected issue follow-up item.

During a quarterly review of PI data, the inspectors identified that the licensee was not reporting leakage data in accordance with NEI 99-02. The IP 71151, PI Verification, dated September 26, 2012, provides guidance to verify PI data submitted by licensees.

IP 71151 states that NEI 99-02 has complete definitions of the PIs and how they are calculated and reported. NEI 99-02 for RCS Leakage states that if in the entire month, plant conditions do not require RCS leakage to be calculated, the data field is left blank for that month and the status Final-N/A is selected.

On February 21, 2012, the inspectors informed the licensee of a concern regarding the licensees submittal of RCS leakage PI data. Specifically, the inspectors identified that the licensee had not submitted the RCS leakage PI data in accordance with the clarifying notes provided in NEI 99-02. The inspectors reviewed licensee procedure LI-AA-204-1001, NRC Performance Indicator Guideline, and found that it states that PI data shall be developed in accordance with the guidance provided in NEI 99-02, Revision 6, and that the data will be prepared using site-specific procedures. The inspectors reviewed NP 5.2.16, NRC Performance Indicators, and noted that the clarifying notes contained in Attachment B were different from those identified in NEI 99-02, Revision 6, and did not contain the information the additional clarifying notes as described. However, the inspectors also noted that the licensee did not take any exceptions as described in the specific interpretations. Also, the inspectors noted that clarifying notes in RCS Specific Activity PI portion of NP 5.2.16 did contain the clarifying note to enter data as Final N/A for months when plant conditions do not require RCS activity to be calculated.

On February 27, 2012, the inspectors held a meeting with the licensee to discuss this concern regarding the data. Specifically, the inspectors identified that the data submitted for Unit 1 for November 2011 and for Unit 2 for April 2011 and May 2011 were incorrect because during these months the associated unit was in a refueling outage for the entire month and thus no RCS leakage data were taken during this time. As such, the data should have been reported, in accordance with NEI 99-02, as Final N/A, instead of zero. During this meeting, the licensee stated that the identified data would be corrected promptly and resubmitted with the next quarters data on April 21, 2012.

On February 28, 2012, the licensee utilized procedure NP 5.2.16, Attachment C, PI Data Calculation, Review, and Approval, form to revise the data for the months identified, and in the comment section, stated that the PI needed to be updated when first quarter 2012 data was entered. On March 2, 2012, the forms received independent verification and approval. No CR was generated at the time in response to the inspectors concern regarding the incorrect PI data. The inspectors noted that licensee procedure PI-AA-204, Condition Identification and Screening Process, stated that the purpose of the CAP is to promote continuous improvement through organizational learning and provide direction on the resolution and documentation of unexpected/unwanted conditions. Specifically, Step 4.2.1 stated that, the CAP database shall be used to document and track significant conditions adverse to quality, conditions adverse to quality, and conditions not adverse to quality to resolution, and that Attachment 3 classified issues that have a potential impact on regulatory confidence, such as routine items identified by NRC inspections, as a significance Level 3 condition adverse to quality at a minimum.

Following the submittal of the first quarter PI data, the inspectors again reviewed the RCS leakage data PIs to verify that the incorrect data had been resubmitted and corrected. The inspectors found that the data remained uncorrected. On May 29, 2012, the inspectors again discussed with the licensee that the RCS leakage PI data was not in accordance with the clarifying notes provided in NEI 99-02. The inspectors also raised the concern that no CR had been generated in response to the initial concern.

Again, the licensee assured the inspectors that corrective action would be taken, ensuring that the PI data would be corrected promptly and resubmitted with the second quarters data on July 21,2012. However, again the inspectors noted that no CR was generated at the time in response to the inspectors concern of the unexpected/unwanted condition of the incorrect PI data.

On August 9, 2012, following the submittal of the second quarter PI data, the inspectors again identified that the data remained uncorrected and immediately communicated this to the licensee. The licensee generated AR01792424, took action to correct the data in the consolidated data entry system, and submitted a procedure change to revise NP 5.2.16 to include clarifying notes in NEI 99-02, Revision 6.

This review constituted the completion of one in-depth problem identification and resolution sample as defined in IP 71152 05.

b. Findings

No findings were identified.

.5 Selected Issue Follow-Up: Shift Manager Working Outage Hours Contrary to Guidance

(Closed URI 05000266/2012002-09)

a. Inspection Scope

During the Unit 1 outage from October 3 through December 17, 2011, the inspectors selected the shift manager (SM) position for review as part of the fatigue assessment activities for IP 71111.20. The inspectors found that the licensee had placed the SM on outage hour controls. The inspectors inquired about the practice and the licensee indicated that alternate licensed and active senior reactor operators (SROs) on operating hours were available to relieve the SM if needed; this designated operator was located in the outage control center. After the inspection concluded, continuing discussions with NRR and operator licensing examiners indicated that this practice may not be acceptable. The inspectors reviewed this practice as a selected issue follow-up item and a URI was issued in integrated IR 05000266/2012002.

This review constituted one in depth problem identification and resolution sample as defined in IP 71152-05.

b. Findings

Shift Manager Working Outage Hours Contrary to Guidance

Introduction:

The inspectors identified a Severity Level lV (SL IV) NCV and associated finding of very low safety significance of 10 CFR 26.207(a) for the licensees failure to perform multiple activities as required when the SM worked outage hours during the Unit 1 outage (U1R33) in fall 2011.

Description:

The inspectors selected fatigue assessment activities for the SM position related to the Unit 1 outage 1R33, conducted from October 3 through December 17, 2011, for review. The inspectors found that the licensee had placed the SM on outage hour controls as indicated by 10 CFR Part 26, Subpart I, Managing Fatigue. The inspectors reviewed the requirements of 10 CFR 26.205 to assess whether the SM position could be exempted from the operating hour restrictions.

The inspectors inquired about the practice, and the licensee indicated that an alternate licensed and active SRO working operating hours was available to relieve the SM as needed. The inspectors determined that the minimum set of required watchstanders for the operating unit were those filling the positions designated by the tables in 10 CFR 50.54(m)(2)(i) and as required by Regulatory Guide (RG) 5.73, Fatigue Management for Nuclear Power Plant Personnel. The inspectors found that the table required two SROs on watch for the operating unit and that these SROs were required to be working operating hours. The licensee was crediting the Unit Supervisor (US) and the relief SM watchstander as the operating hours watchstanders. The inspectors reviewed guidance to determine if the relief SM could be credited as an additional SM on watch.

The inspectors determined that to be considered a watchstander, the individual must fill a position on a shift crew that requires an individual to be licensed by the licensees TSs.

Additionally, personnel in excess of the TS requirement can also be credited as a watchstander if they are meaningfully and fully engaged in the functions and duties of the analogous minimum licensed positions required by TSs, and the licensee has procedural and administrative controls that provide a list of all the licensee shift crew positions, including title, description of duties, and indication of which positions are required by TSs.

The inspectors found that the relief SM was located in the outage control center performing outage-related duties and was not meaningfully and fully engaged in the activities of a watchstander on the operating unit. In addition, procedures were not available that allowed the relief SM to be credited as an additional SM. Therefore, the inspectors concluded that the relief SM could not be credited as an SRO on watch.

At the inspectors request, the licensee reviewed the work hour tracking system with the presumption that the SM was required to work operating hours. The licensee found multiple occurrences where SMs had exceeded the working hour requirements for the operating unit. Title 10 CFR 26.207(a) indicates that waivers to the operating hours requirements may be granted if the operations SM determines the waiver to be necessary to mitigate or prevent specific conditions; that a face-to-face fatigue assessment is performed which provides reasonable assurance of safety; and, that waivers shall be granted only to address circumstances that could not have been reasonably controlled. The inspectors concluded that all three of these requirements were not met for each occurrence of a SM exceeding working hour controls. The licensee entered this issue into the CAP as AR01797782, Potential Violation of Fatigue Rule. The corrective actions to restore compliance and to address recurrence included initiating an apparent cause evaluation, revising procedure AD-AA-101-1004 to include the SM as an operator that shall adhere to online hours, and scheduling SMs for online hours for future outages.

Analysis:

The inspectors determined that the failure to enact appropriate work hour controls as required by 10 CFR 26.207(a) for the SMs working outage hours was a performance deficiency warranting further evaluation. The finding was determined to be more than minor in accordance with IMC 0612, Appendix B, Issue Screening, because if left uncorrected, the exclusion of workers from work hour controls could have led to a more significant safety concern due to personnel exceeding work hour limits while performing safety related or risk significant activities. Specifically, without proper fatigue assessments, incorrect assessment or directions could be provided by the SM for routine activities or during transient/emergency response.

Because violations of 10 CFR Part 26 are considered to be violations that potentially impact the regulatory process, they are dispositioned using the traditional enforcement process instead of the Reactor Oversight Process SDP. However, the inspectors determined the underlying finding could be evaluated using the SDP in accordance with IMC 0609, Attachment 0609.04, Tables 2 and 3, dated June 19, 2012, and Appendix M, Significance Determination Process Using Qualitative Criteria, dated April 12, 2012.

The inspectors determined that the finding was of very low safety significance (SL IV)because no deficiencies which affected risk significant structures, systems, or components occurred as a result of SM fatigue.

The finding has a cross-cutting aspect in the area of problem identification and resolution, self and independent assessment, because the licensee failed to conduct sufficient in-depth self-assessments. Specifically, the licensee conducted a self-assessment of the fatigue rule annually with its corporate licensing department giving the licensee the prior opportunity to identify and correct this issue had the self-assessments been more rigorous (P.3(a)).

Enforcement:

Title 10 CFR 26.207(a) states in part that waivers for work hour controls may be granted provided that:

(1) an SM determines that the waiver is necessary to mitigate or prevent a condition adverse to safety, and that

(2) a supervisor assess the individual face-to-face and determine that there is reasonable assurance that the individual will be able to safely and competently perform his or her duties during the additional work period for which the waiver will be granted. Also, 10 CFR 26.207(a)states that licensees shall rely on the granting of waivers only to address circumstances that could not have been reasonably controlled.

Contrary to this, during the Unit 1 outage conducted between October 3 and December 17, 2011, on multiple occasions, the licensee failed to comply with the aforementioned requirements of 10 CFR 26.207(a). Specifically, for each circumstance where an SM exceeded operating hours, there was not a condition adverse to safety, the SMs supervisor did not perform a required face-to-face assessment of the SM, and the circumstance of placing SMs on outage hours was foreseeable and controllable because additional personnel could have been added to the shift to perform the related outage activities.

This violation is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy, because it was SL IV and was entered into the licensees CAP (as AR01797782) to address recurrence (SL IV NCV 05000266/2012004-07; 05000301/2012004-07, Shift Manager Working Outage Contrary to Guidance).

4OA3 Follow-Up of Events and Notices of Enforcement Discretion

.1 Response to Unplanned or Non-Routine Events

a. Inspection Scope

The inspectors reviewed the plants response to the following third quarter 2012 non-routine events:

• Unit 1 unplanned reactor trip as a result of turbine control system malfunction on August 14;

• Unit 2 turbine load reject due to a turbine first stage pressure instrument malfunction on August 20; and

• Unit 1 downpowered to 55 percent to remove the main feedwater pump 1B from service due to increasing vibrations on August 29. Unit 1 increased power on September 1, reaching 87 percent when increased vibrations were again noted.

On September 2, Unit 1 was downpowered to 56 percent to perform additional troubleshooting and subsequent repair of the centering ring. The unit was returned to full load on September 5.

Documents reviewed are listed in the Attachment to this report.

This event follow-up review constituted three samples as defined in IP 71153-05.

b. Findings

No findings were identified.

4OA5 Other Activities

.1 Institute of Nuclear Power Operations (INPO) Training Accreditation Report Review

a. Inspection Scope

The inspectors reviewed the final training accreditation report issued in July 2012 for a visit by INPO from June 11 through June 15, 2012. The inspectors reviewed the report to ensure that issues identified were consistent with the NRC perspectives of licensee performance and to verify if any significant safety issues were identified that required further NRC follow-up.

b. Findings

No findings were identified.

.2 (Closed) Plant Modifications in Support of Extended Power Uprate (EPU)

a. Inspection Scope

The EPU license amendment was approved on May 3, 2011, which increased the power level of Units 1 and 2 from 1540 megawatts thermal (MWt) to 1800 MWt, approximately 17 percent. Unit 2 achieved criticality for the implementation of EPU on June 13, 2011, and power exceeded the old licensed thermal power limit (1540 MWt) on June 27, 2011.

Unit 1 achieved criticality for the implementation of EPU on December 12 and power exceeded the old licensed thermal power limit (1540 MWt) on December 23, 2011.

This report serves to document completion of IP 71004, Extended Power Uprate, for Point Beach Nuclear Plant, Units 1 and 2. As required by the IP, a summary of all the inspection samples are described in the attachment to this report, and references the baseline IP that performed the sample and the IR in which it was documented.

b. Findings

Failure to Incorporate Westinghouse Owners Group (WOG) Emergency Response Guideline (ERG), Revision 2 into the Emergency Operating Procedures (EOPs)

Introduction:

As part of the review to EPU, the inspectors identified a finding of very low safety significance (Green) and associated NCV of TS 5.4, Procedures, because the licensee failed to maintain the EOPs, specifically, with the safety-significant changes provided in WOG ERG, Revision 2.

Description:

During the week of June 18, 2012, the inspectors found that the WOG ERG, Revision 2, was provided to Point Beach Nuclear Plant on May 27, 2005. Over the next several years, the Revision 2 changes became linked to a Calculation and Reconstitution Project, and the associated NRC commitment due dates were revised several times, citing lack of resources due to EPU, AFW Modifications, and Alternate Source Term issues.

In October 2007, an NCV for an inadequate EOP, associated with WOG ERG, Revision 2, was identified by the NRC during an initial operator licensing exam. The resulting revision to EOP-3, Steam Generator Tube Rupture, addressed only the specific safety issue identified. WOG ERG, Revision 2, issued in May 2005, included other changes with very specific explanations of their safety significance.

In 2009, the licensee again reviewed its WOG ERG, Revision 2, incorporation schedule and concluded that the window for successful 2009 implementation had passed, citing the training and calculation issues to be addressed. The comments associated with the schedule revision also stated that the station priority was successful EPU project implementation, described the resources required for the EPU project completion, and then proposed that the WOG ERG revision should be implemented by August 2011, on both fully uprated units. Delays continued due to work remaining versus competing station priorities until the latest commitment date of September 30, 2013, was established.

The most recent commitment (NRC 2012-0025), dated April 17, 2012, estimated completion of the EOP revisions by September 30, 2013. However, AR01776901, written on June 18, 2012, described the following concerns with this latest commitment:

• EOP changes for WOG ERG, Revision 2 have been delayed multiple times due to less-than-adequate change management plans (CMPs) and dedication of insufficient resources to complete the needed changes; and

• CMPs were either less-than-adequate or non-existent, and the current commitment was associated with a CMP that did not meet the requirements of procedure PI-AA-202-1000, Change Management.

The current CMP 017716322 was provided for NRC review and the following additional comments and questions were raised by the inspectors:

• the consequences of not changing were identified as Possible INPO/NRC attention and did not mention the safety benefit to be gained; the licensee agreed with the comment and wrote AR01778333 to revise the CMP;

• the current contingency plans were to escalate the issue if problems arose and submit a commitment change if failure to meet the commitment date was expected; when asked how these contingency plans differed from previous plans, the licensee acknowledged their inadequacy and wrote AR01778333 to develop stronger contingency plans; and

• commitments (past and present) and corresponding documents referred to WOG ERG, Revision 2A, which did not exist; Revision 2 was the correct revision number, so the licensee wrote AR01778136 to clarify the WOG ERG revision number.

The licensees failure to incorporate WOG ERG, Revision 2, went significantly beyond the current industry standard for incorporation of the two years specified in Section 6.3.7.5 of WCAP-17433-NP, Pressurized Water Reactor Owners Group Emergency Operating Procedure Maintenance Program Standard.

As a result, the current EOPs remained at WOG ERG, Revision 1C, issued in 1997, which lacked several safety-significant improvements to operator response times to limit radioactive releases. For example, the WOG ERG, Revision 2 changes included:

• reordered EOP-3 procedure steps to expedite identification and isolation of the ruptured generator;

• added a CAUTION to preclude an inappropriate transition to CSP-P.1, Response To Imminent Pressurized Thermal Shock Condition; and

• deleted a redundant step to expedite procedural execution.

Analysis:

The inspectors determined that the failure by the licensee to adequately maintain the EOPs was a violation and a performance deficiency warranting further review. The finding was determined to be more than minor in accordance with IMC 0612, Appendix B, Issue Screening, because it was associated with the Mitigating Systems Cornerstone attribute of procedure quality and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the inspectors determined that the failure to update EOPs to implement Revision 2 of the WOG ERGs significantly beyond the current industry standard of two years would result in a delay for reactor operators trying to terminate the Primary-To-Secondary Leakage during a Steam Generator Tube Rupture (SGTR) event. The step deletion/moves of Revision 2 of the ERGs were part of a tactic of rearranging the steps in EOP-3 in order to improve operator response time in accomplishing the EOP-3 strategic actions (identify, isolate, cooldown, depressurize, and terminate SI). The objectives of the step sequence rearrangement were to allow faster termination of SI and SG tube leakage, and thus minimize offsite radiological releases and the potential for SG overfill.

The inspectors evaluated the finding using IMC 0609, Attachment 0609.04, Tables 2 and 3, and Appendix A, Exhibit 2 for the the Mitigating Systems Cornerstone. The inspectors answered Yes to Exhibit 2, Question A.1 in Appendix A for mitigating structures, systems, and components, and functionality. The inspectors determined that the issue was a design or qualification deficiency confirmed not to result in a loss of operability. Therefore, the inspectors determined the finding to be of very low safety significance (Green).

This finding has a cross-cutting aspect in the area of human performance, resources, because the licensee failed to assure resources were available and adequate to complete the WOG ERG, Revision 2, EOP updates in a timely manner commensurate with risk and safety (H.2(c)). The inspectors reviewed the licensees causal analysis where the licensee proposed that the issue was associated with problem identification and resolution, corrective actions, because they did not take appropriate corrective actions to address safety issues in a timely manner by submitting commitment changes to the NRC multiple times, extending the implementation of WOG ERG, Revision 2, since it was issued in 2005. The inspectors considered this aspect, but found that a failure to apply appropriate resources to enable WOG ERG, Revision 2, implementation was the underlying cause of the repeated extensions. Additionally, Nuclear Oversight AR01776901, Implementation of Emergency Response Guidelines Revision 2, found that Less than adequate change management and dedicated resources contributed to the delays noted that inadequate resources were applied, and further supported the inspectors conclusions. Therefore, the cross-cutting aspect remained in the area of human performance, resources.

Enforcement:

TS 5.4, Procedures, required, in part, that written procedures be established, implemented, and maintained for the EOPs required to implement the requirements of NUREG-0737, Clarification of TMI Action Plan Requirements, and to NUREG-0737, Supplement 1. Specifically, Item I.C.1 of NUREG-0737, and NUREG-0737, Supplement 1, Section 7, required, in part, the development of EOPs to cover transients and accidents including an event that required the response to an SGTR event.

Contrary to the above, from May 27, 2005, to date, the licensee failed to maintain the Units 1 and 2 EOPs to meet the current industry standard of WOG ERG, Revision 2.

Specifically, the licensee failed to implement changes that included rearranging EOP-3 steps to improve operator response time in accomplishing the EOP-3 strategic actions to allow faster termination of SI and SG tube leakage, thus minimizing the potential for SG overfill and offsite radiological releases.

This violation is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy because it was of very low safety significance and was entered into the licensees CAP (as AR01779635) to address recurrence (NCV 05000266/2012004-08; 05000301/2012004-08, Failure to Incorporate WOG ERG, Revision 2 into the EOPs).

.3 Operational Testing of an Independent Spent Fuel Storage Facility Installation (ISFSI) at

Operating Plants (60855.1)

a. Inspection Scope

The inspectors observed and evaluated select licensee loading, processing, and transfer operations involving the second Standardized Nutech Horizontal Modular Storage (NUHOMS) 32PT canister of the licensees 2012 dry fuel storage campaign to verify compliance with the applicable Certificate of Compliance (CoC) conditions, the associated TSs, and ISFSI procedures. Specifically, the inspectors observed: shield plug placement in the dry shielded canister (DSC); movement of the transfer cask (TC)containing the DSC from the spent fuel pool (SFP) to the decontamination area; removal of water from the DSC; inner cover welding and non-destructive evaluations; helium blowdown; top cover welding and non-destructive evaluation; TC lifting to the transfer trailer; and movement of the TC on the transfer trailer to the ISFSI pad.

The licensee maintains an ISFSI at the Point Beach Nuclear Plant. The ISFSI stores both Ventilated Storage Casks (VSC) and NUHOMS 32PT canisters in Horizontal Storage Modules (HSM). The inspectors performed tours of the ISFSI to assess the material condition of the pads, VSCs, and HSMs. The inspectors reviewed the licensees evaluations of flammable materials located near the ISFSI and of the radiation monitoring program. Additionally, the inspectors performed independent radiation surveys around the ISFSI pad, VSCs, and HSMs. The inspectors reviewed procedures used to perform ISFSI preparation, loading, sealing, transfer, monitoring, and storage activities.

The inspectors reviewed the licensees procedures for compliance with its control of heavy loads program and associated crane standards. The inspectors reviewed the licensees certificate of conformance for the TC and associated lift yoke. The inspectors reviewed the licensees evaluations of cask lay down areas within the PAB and in the SFP.

The inspectors reviewed the licensees evaluations associated with fuel characterization and selection for storage. The inspectors reviewed the licensees evaluation to characterize fuel as fuel debris, damaged, or intact fuel. The licensee did not plan to load any damaged fuel assemblies or fuel debris during this campaign. The inspectors reviewed the campaign cask fuel selection packages to verify that the licensee was loading fuel in accordance with the CoC-approved contents.

The inspectors reviewed CRs, and the associated corrective actions. The inspectors reviewed the licensees 10 CFR 72.48 screenings and the changes to the licensees 10 CFR 72.212 evaluations since the last ISFSI inspection.

b. Findings

(1) Failure to Perform Adequate Evaluations to Ensure Compliance with 10 CFR 72.212(b)(6) and 10 CFR 72.122(b)(2)(i)

Introduction:

The inspectors identified an SL IV NCV of 10 CFR 72.146, Design Control, for the licensees failure to perform adequate evaluations to ensure compliance with 10 CFR 72.122(b)(2)(i) and 10 CFR 72.212(b)(6). Specifically, the inspectors identified that the licensee failed to evaluate that the reactor site parameters, including analyses of earthquakes, were enveloped by the TC design basis and that the TC was designed to withstand the effects of natural phenomena including earthquakes.

Description:

Title 10 CFR 72.122(b)(2)(i), Overall Requirements, states, in part, that structures, systems, and components important to safety must be designed to withstand the effects of natural phenomena such as earthquakes, tornadoes, lightning, hurricanes, floods, tsunami, and seiches, without impairing their capability to perform their intended design functions.

Title 10 CFR 72.212(b)(6), Conditions of General License Issued Under 72.210, states that the licensee shall review the Safety Analysis Report referenced in the Certificate of Compliance and the related NRC Safety-Evaluation Report, prior to use of the general license, to determine whether or not the reactor site parameters, including analyses of earthquake intensity and tornado missiles, are enveloped by the cask design bases considered in these reports. The results of this review must be documented in the evaluation made in Paragraph (b)(2) of this section.

The NUHOMS Updated Final Safety Analysis Report (UFSAR), Revision 11, does not evaluate the effects of a TC tipover due to TC rocking or sliding in the vertical orientation. At the Point Beach Nuclear Plant, while the TC is located on the decontamination stand within the PAB, the TC is not engaged to a handling or restraint system. Therefore, during an earthquake, there is a potential that seismic forces could cause rocking or sliding which could cause the TC to tip over.

During review of Calculation 03Q0383-C-001, Modification of the Cask Decontamination Structure, Revision 0, the inspectors noted that the TC had not been evaluated for the effects of a seismic forces while on the decontamination stand and, in addition, the decontamination stand had not been evaluated for seismic forces. The inspectors determined that the TC was not analyzed for cask overturning or sliding which could lead to a tipover during an earthquake which could exceed the cask design basis.

In addition, the inspectors performed a review of Calculation 2003-0069, NUHOMS Dry Cask-Spent Fuel Pool Reanalysis, Revision 0, which performed a stability analysis of the TC in the SFP to ensure rocking or sliding did not occur. Rocking and sliding in the SFP is undesirable as the TC has the ability to impact fuel assembly racks or the SFP structure if rocking or sliding is allowed. The inspectors noted that the licensee utilized a sliding coefficient of friction between the TC and SFP floor of 0.74 for the sliding assessment. The calculation referenced a Marks Standard Handbook for Mechanical Engineers, Table 1, static coefficient of friction between mild steel and mild steel in a dry environment. The inspectors determined that the use of 0.74 as the coefficient of friction for sliding assessments was inappropriate for actual field conditions of wet stainless steel on stainless steel, and as such could underestimate the amount of sliding that could occur in the SFP.

As discussed in the above examples, the inspectors determined that the licensee failed to determine that the reactor site parameters, including analyses of effects of natural phenomenon including earthquakes, were enveloped by the cask design bases and subsequently failed to perform an additional analysis to ensure that the requirements of 10 CFR 72.122(b)(2)(i) were met. Subsequent to the inspectors inquiry, the licensee revised Calculation 03Q0383-C-001 and Calculation 2003-0069. The revised calculations demonstrated that overturning or sliding of the TC on the decontamination stand would not occur due to the effects of an earthquake and that sliding would not occur in the SFP. The inspectors reviewed the subsequent calculation and had no further questions.

Analysis:

The inspectors determined that the licensees failure to perform a calculation evaluating the effects of an earthquake on the TC was a violation that warranted a significance evaluation.

Consistent with the guidance in Section 2.2 of the NRC Enforcement Policy, ISFSIs are not subject to the SDP and traditional enforcement will be used for these facilities.

The violation was determined to be more than minor in accordance with IMC 0612, Appendix B, Issue Screening, and Appendix E, Example 3i. Specifically, the licensees lack of evaluation did not assure cask integrity during a design basis earthquake and an additional calculation was required to evaluate the effects of the design basis earthquake during DSC processing operations in the PAB on the cask decontamination stand in accordance with the ISFSI licensing/design basis analysis requirements.

Consistent with the guidance in the NRC Enforcement Manual, Section 2.6.D, if a violation does not fit an example in the enforcement policy violation examples, it should be assigned a severity level:

(1) commensurate with its safety significance; and,

(2) informed by similar violations addressed in the Violation Examples. The violation screened as having very low safety significance (SL IV). Specifically, following the inspection inquiry the licensee revised its calculations and determined that overturning and sliding of the transfer cask in the PAB on the cask decontamination stand and in the SFP would not occur during the design basis earthquake.

In accordance with Section 2.2 of the NRC Enforcement Policy, ISFSIs are not subject to the SDP and, thus, traditional enforcement will be used for these facilities and thus a cross-cutting aspect is not assigned to this violation.

Enforcement:

Title 10 CFR 72.146, Design Control, states, in part, that The licensee shall establish measures to ensure that applicable regulatory requirements and the design basis, as specified in the license for those structures, systems, and components to which this section applies, are correctly translated into specifications, drawings, procedures, and instructions. These measures must include provisions to ensure that appropriate quality standards are specified and included in design documents and that deviations from standards are controlled.

Contrary to the above, until June 28, 2012, the licensee had failed to establish measures to ensure that applicable regulatory requirements and the design basis were correctly translated into specifications, drawings, procedures, and instructions. Specifically, the licensee failed to evaluate the effects of natural phenomena, including earthquakes, on the TC.

This violation is being treated as an NCV, consistent with Section 3.1.1 of the NRC Enforcement Manual. The licensee documented the violation in the CAP (as AR01780357) and initiated actions to evaluate the described condition (SL IV NCV 05000266/2012004-09; 05000301/2012004-09; 07200005/2012001-01, Failure to Perform Adequate Evaluations to Ensure Compliance with 10 CFR 72.212(b)(6) and 10 CFR 72.122(b)(2)(i)).

(2) Inadequate Procedural Guidance for Heavy Loads Operations

Introduction:

The inspectors identified a finding of very low safety significance (Green)and associated NCV of 10 CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings," for the licensees failure to have adequate procedures in place to ensure that heavy loads were operated safely within the PAB.

Description:

The Point Beach Nuclear Plant FSAR, Section A3.4, Auxiliary Building Crane, states, in part, that It was committed that the PAB crane would be modified to make it single failure proof. The inspectors reviewed correspondence between the licensee and the NRC, dated July 19, 1978, in response to requests for additional information regarding Amendments 35 and 41 to the operating license which described the single failure proof handling system. The inspectors determined that the licensee identified the ambient temperature of the PAB as 60°F [degrees Fahrenheit] minimum which would exceed the nil-ductility transition temperature plus 30°F requirements for steel used in the girders and the end trucks; and therefore, the licensee determined that cold proof testing would not be performed as described in RG 1.104, Overhead Crane Handling Systems for Nuclear Power Plants. These temperature requirements are necessary to protect against brittle fracture of structural components below the nil-ductility transition temperature.

On June 19, 2012, the inspectors determined that the licensee had not imposed a minimum operating temperature of 60°F for the PAB crane for heavy load lifts in crane operating procedures. The licensee documented the issue in the CAP as AR01783306, and initiated actions to revise procedures to identify the minimum operating temperature of the PAB crane.

Analysis:

The inspectors determined that the licensees failure to incorporate minimum crane operating temperature limits into procedures was contrary to the instructions, procedures, and drawings measures per 10 CFR Part 50, Appendix B, requirements and was a performance deficiency. The finding was determined to be more than minor in accordance with IMC 0612, Appendix B, Issue Screening, because it was associated with the Barrier Integrity Cornerstone attribute of procedure quality and adversely affected the cornerstone objective to provide reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events because a PAB crane heavy load drop could cause damage to spent fuel. Additionally, if left uncorrected, it could result in crane structure failures and potentially heavy load drops over the SFP if lifts occurred below the allowable temperature.

The inspectors evaluated the finding using IMC 0609, Attachment 0609.04, Tables 2 and 3 and Appendix A, Exhibit 3 for the Barrier Integrity Cornerstone. The inspectors answered No to the Exhibit 3 questions in Appendix A for SFP since the finding was a procedure requirement issue confirmed not to result in a heavy load drop and no damage to spent fuel. Therefore, the finding was determined to be of very low safety significance (Green).

In accordance with IMC 0612, Section 06.03.c, a cross-cutting aspect will not be assigned to this finding as it has occurred outside of the nominal three-year period and is not representative of present performance.

Enforcement:

Title 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, states, in part, that the licensee shall prescribe activities affecting quality by documented instructions, procedures, or drawings of a type appropriate to the circumstances and shall require that these instructions, procedures, and drawings be followed. The instructions, procedures, and drawings must include appropriate quantitative or qualitative acceptance criteria for determining that important activities have been satisfactorily accomplished.

Contrary to the above, on June 29, 2012, the inspectors determined that the licensee failed to impose a minimum operating temperature of 60°F for the PAB crane for heavy load lifts in crane operating procedures.

This violation is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy because it was of very low safety significance and was entered into the licensees CAP (as AR01783306) to address recurrence (NCV 05000266/2012004-10; 05000301/2012004-10; 07200005/2012001-02, Inadequate Procedural Guidance for Heavy Loads Operations).

.4 (Discussed) URI 05000266/2011005-03; 05000301/2011005-03, Condition Reports and

URIs Potentially Affecting Safety System Functional Failure Performance Indicator The inspectors opened a URI in the fourth quarter 2011 quarter integrated IR 05000266/2011005; 05000301/2011005, relating to safety system functional failures that may have affected the PI reporting criteria. On August 28, 2012, the licensee submitted licensee event report (LER) 05000266/2012-003-00, 2B04 Safeguards 480V Bus De-Energized, which discussed one AR related to a single item discussed in the subject URI. The LER and its relationship to the related URI will be inspected in a future report.

.5 (Discussed) NRC Temporary Instruction (TI) 2515/187, Inspection of Near-Term Task

Force Recommendation 2.3 Flooding Walkdowns, and NRC TI 2515/188, Inspection of Near-Term Task Force Recommendation 2.3 Seismic Walkdowns

a. Inspection Scope

The inspectors accompanied the licensee on a sampling basis, during the flooding and seismic walkdowns, to verify that the licensees walkdown activities were conducted using the methodology endorsed by the NRC. These walkdowns are being performed at all sites in response to a letter from the NRC to licensees, entitled Request for Information Pursuant to Title 10 of the Code of Federal Regulations 50.54(f) Regarding Recommendations 2.1, 2.3, and 9.3, of the Near-Term Task Force Review of Insights from the Fukushima Dai-Ichi Accident, dated March 12, 2012 (ADAMS Accession No. ML12053A340).

3 of the March 12, 2012, letter requested licensees to perform seismic walkdowns using an NRC-endorsed walkdown methodology. Electric Power Research Institute (EPRI) document 1025286 titled, Seismic Walkdown Guidance, (ADAMS Accession No. ML12188A031) provided the NRC-endorsed methodology for performing seismic walkdowns to verify that plant features, credited in the current licensing basis (CLB) for seismic events, are available, functional, and properly maintained.

4 of the letter requested licensees to perform external flooding walkdowns using an NRC-endorsed walkdown methodology (ADAMS Accession No. ML12056A050). Nuclear Energy Industry 12-07, Guidelines for Performing Verification Walkdowns of Plant Protection Features (ADAMS Accession No. ML12173A215), provided the NRC-endorsed methodology for assessing external flood protection and mitigation capabilities to verify that plant features, credited in the CLB for protection and mitigation from external flood events, are available, functional, and properly maintained.

b. Findings

Findings or violations associated with the flooding and seismic walkdowns, if any, will be documented in the fourth quarter 2012 integrated IR.

4OA6 Meetings, Including Exit

.1 Exit Meeting Summary

On October 2, 2012, the inspectors presented the inspection results to Mr. C. Trezise, 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.

.2 Interim Exit Meetings

Interim exits were conducted for:

• the inspection results for ISFSI inspection with Mr. J. Petro, Licensing Manager, and other members of the licensee staff, by teleconference, on July 10, 2012;

• the inspection results for the EOP and URI Closure Inspections with Mr. R. Wright, Plant General Manager, and other members of the licensees staff, on June 22, 2012, and by teleconference with Mr. J. Petro, Licensing Manager, and other members of the licensee staff, on July 12, 2012.

The inspectors confirmed that none of the potential report input discussed was considered proprietary. Proprietary material received during the inspection was returned to the licensee.

4OA7 Licensee-Identified Violations

The following violation of very low safety significance (Green) or SL IV was identified by the licensee and is a violation of NRC requirements which meets the criteria of the NRC Enforcement Policy for being dispositioned as an NCV.

• The licensee identified a finding of very low safety significance (Green) and associated NCV of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings. This regulation requires in part that activities affecting quality be prescribed by procedures of a type appropriate to the circumstances and be accomplished in accordance with these procedures.

Contrary to the above, the licensee identified during the performance of operator rounds on May 11, 2012, that a scaffolding modification interfered with the operation of the EDG G-01 ventilation gravity louvers contrary to the requirements of procedure MI 32.9, Scaffolding Program. The cause of the issue was determined to be the result of the related procedure not requiring an operations department review of modifications made to scaffolding after initial installation. The licensee entered this into the CAP as AR01795985 and AR01766629 and implemented corrective actions to remove the interference and modify the inadequate procedure.

The performance deficiency was determined to be more than minor because it was associated with the Mitigating Systems Cornerstone attribute of equipment performance and adversely affected the associated cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the erected scaffolding impacted the EDG G-01 ventilation gravity louvers operation impacting the EDGs operability. The inspectors evaluated the issue using IMC 0609, Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings, Tables 2 and 3, dated June 19, 2012, and IMC 0609, Appendix A, Exhibit 2, for the Mitigating System Cornerstone and answered No to the mitigating SSCs and functionality questions; therefore, the issue screened as very low safety significance (Green).

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

L. Meyer, Site Vice-President

R. Wright, Plant General Manager

C. Trezise, Engineering Director

J. Costedio, Licensing Manager

R. Admundson, Operations Training Exam Coordinator

J. Pierce, Training

B. Scherwinski, Licensing

K. Locke, Licensing

J. Rogers, OPT Supervisor

W. Hennessy, Licensing Supervisor / Acting Licensing Manager

L. Rogers, Site ISFSI Project Manger

C. Gears, Corporate ISFSI Project Manager

D. Forter, Site Project Manager

K. Locke, Licensing

A. Nash, Engineering Supervisor

G. Worley, Radiation Protection Supervisor

Nuclear Regulatory Commission

M. Kunowski, Branch Chief, Division of Reactor Projects Branch 5

Attachment

LIST OF ITEMS

Opened

05000266/2012004-01; FIN Failure to Adequately Control Materials Classified As

05000301/2012004-01 High Winds/Tornado Hazards (Section 1R01)

05000266/2012004-02; NCV Failure to Implement Risk Management Actions During

05000301/2012004-02 Various Emergent Work Activities (Section 1R13)

05000301/2012004-03 NCV Plant Operation with an Unacceptable ASME Code Class 2 Pressure Boundary Flaw (Section 1R15)

05000266/2012004-04; NCV Weld Design Deficiency in Emergency Diesel Generator

05000301/2012004-04 Missile Protection Barriers (Section 1R18)

05000301/2012004-05 NCV Boric Acid Not Removed from Containment Isolation Valve as Required by Procedure (Section 1R20.1(1))

05000301/2012004-06 NCV Transient Materials Not Removed from Containment Prior to Reactor Startup (Section 1R20.1(2))

05000266/2012004-07; SL IV Manager Working Outage Hours Contrary to Guidance

05000301/2012004-07 NCV (Section 4OA2.5)

05000266/2012004-08; NCV Failure to Incorporate WOG ERG, Revision 2, into the

05000301/2012004-08 EOPs (Section 4OA5.2)

05000266/2012004-09; SL IV Failure to Perform Adequate Evaluations to Ensure

05000301/2012004-09; NCV Compliance with 10 CFR 72.212(b)(6) and 200005/2012001-01 10 CFR 72.122(b)(2)(i) (Section 4OA5.3(1))

05000266/2012004-10; NCV Inadequate Procedural Guidance for Heavy Loads

05000301/2012004-10; Operations (Section 4OA5.3(2))

200005/2012001-02

Closed

05000266/2012004-01; FIN Failure to Adequately Control Materials Classified As

05000301/2012004-01 High Winds/Tornado Hazards (Section 1R01)

05000266/2011004-01; URI Potential Failure to Correctly Implement a Systems

05000301/2011004-01 Approach to Training for the Licensed Operator Requalification Program (Section 1R11)

05000266/2012004-02; NCV Failure to Implement Risk Management Actions During

05000301/2012004-02 Various Emergent Work Activities (Section 1R13)

05000301/2012004-03 NCV Plant Operation with an Unacceptable ASME Code Class 2 Pressure Boundary Flaw (Section 1R15)

05000266/2012004-04; NCV Weld Design Deficiency in Emergency Diesel Generator

05000301/2012004-04 Missile Protection Barriers (Section 1R18)

05000301/2012004-05 NCV Boric Acid Not Removed from Containment Isolation Valve as Required by Procedure (Section 1R20.1(1))

05000301/2012004-06 NCV Transient Materials Not Removed from Containment Prior to Reactor Startup (Section 1R20.1(2))

05000266/2012002-09 URI Shift Manager Working Outage Hours Contrary to Guidance (Section 4OA2.5)

05000266/2012004-07; SL IV Shift Manager Working Outage Hours Contrary to

05000301/2012004-07 NCV Guidance (Section 4OA2.5)

05000266/2012004-08; NCV Failure to Incorporate WOG ERG, Revision 2, into the

05000301/2012004-08 EOPs (Section 4OA5.2)

Attachment

05000266/2012004-09; SL IV Failure to Perform Adequate Evaluations to Ensure

05000301/2012004-09; NCV Compliance with 10 CFR 72.212(b)(6) and 200005/2012001-01 10 CFR 72.122(b)(2)(i) (Section 4OA5.3(1))

05000266/2012004-10; NCV Inadequate Procedural Guidance for Heavy Loads

05000301/2012004-10; Operations (Section 4OA5.3(2))

200005/2012001-02

Discussed

05000266/2011005-03; URI Condition Reports and URIs Potentially Affecting Safety

05000301/2011005-03 System Functional Failure Performance Indicator (Section 4OA5.2(4))

TI 2515/187 Inspection of Near-Term Task Force Recommendation 2.3 Flooding Walkdowns (Section 4OA5.5)

TI 2515/188 Inspection of Near-Term Task Force Recommendation 2.3 Seismic Walkdowns (Section 4OA5.5)

Attachment