IR 05000266/2013007

IR 05000266-13-007; 05000301-13-007; 07/15/2013 - 08/28/2013; Point Beach Nuclear Plant; Problem Identification and Resolution

ML13253A027
Person / Time
Site:	Point Beach
Issue date:	09/09/2013
From:	Patricia Pelke NRC/RGN-III/DNMS/MLB
To:	Meyer L Point Beach
References
IR-13-007
Download: ML13253A027 (25)

Text

tember 9, 2013

SUBJECT:

POINT BEACH NUCLER PLANT - NRC PROBLEM IDENTIFICATION AND RESOLUTION INSPECTION REPORT 05000266/2013007; 05000301/2013007

Dear Mr. Meyer:

On August 28, 2013, the U.S. Nuclear Regulatory Commission (NRC) completed a Problem Identification and Resolution inspection at the Point Beach Nuclear Plant. The enclosed inspection report documents the inspection results, which were discussed at an interim exit meeting on August 2, 2013, with you and other members of your staff, and a final exit meeting on August 28, 2013, (via teleconference) with Ms. F. Hennessy.

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

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

On the basis of the samples selected for review, there were no findings identified during this inspection. The team concluded that the corrective action program was generally effective in identifying, evaluating and correcting issues. The licensee had a low threshold for identifying issues and entering them into the corrective action program. A risk based approach was used to determine the significance of the issues and that drove the priority of issue evaluation and resolution. Corrective actions were generally implemented in a timely manner, commensurate with their safety significance. Operating experience was entered into the corrective action program and appropriately evaluated. The use of operating experience was integrated into daily activities and found to be effective in preventing similar issues at the plant. In addition, self-assessments, audits, and effectiveness reviews were found to be conducted at appropriate frequencies with sufficient depth for all departments. The assessments reviewed were thorough and effective in identifying plant performance deficiencies, programmatic concerns, and improvement opportunities. On the basis of the interviews conducted, the inspectors did not identify any impediment to the establishment of a safety conscious work environment. Your staff was aware of and generally familiar with the corrective action program and other processes, including the Employee Concerns Program, through which concerns could be raised. . In accordance with 10 CFR 2.390 of the NRCs Rules of Practice, a copy of this letter and its enclosure 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 Documents 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/

Patricia Pelke, Acting Chief Branch 6 Division of Reactor Projects Docket Nos. 50-266; 50-301 License Nos. DPR-24; DPR-27

Enclosure:

Inspection Report No. 05000266/2013007; 05000301/2013007 w/Attachment: Supplemental Information

REGION III==

Docket Nos: 50-266; 50-301 License Nos: DPR-24; DPR-27 Report Nos: 05000266/2013007; 05000301/2013007 Licensee: NextEra Energy Point Beach, LLC Facility: Point Beach Nuclear Plant, Unit 1 and Unit 2 Location: Two Rivers, WI Dates: July 15, 2013, through August 28, 2013 Team Leader: R. Ng, Project Engineer Inspectors: M. Thorpe-Kavanaugh, Resident Inspector R. Lerch, Project Engineer D. Jones, Reactor Engineer G. ODwyer, Reactor Inspector Approved by: P. Pelke, Acting Chief Branch 6 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

Inspection Report 05000266/2013007; 05000301/2013007; 07/15/2013 - 08/28/2013;

Point Beach Nuclear Plant; Problem Identification and Resolution.

This inspection was performed by four region-based inspectors and the Point Beach Resident Inspector. 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.

Problem Identification and Resolution On the basis of the samples selected for review, the team concluded that the corrective action program (CAP) at Point Beach Nuclear Plant was generally effective in identifying, evaluating and correcting issues. The licensee had a low threshold for identifying issues and entering them into the CAP. A risk based approach was used to determine the significance of the issues and that drove the priority of issue evaluation and resolution. Corrective actions were generally implemented in a timely manner, commensurate with their safety significance. Operating experience was entered into the CAP and appropriately evaluated. The use of operating experience was integrated into daily activities and found to be effective in preventing similar issues at the plant. In addition, self-assessments, audits, and effectiveness reviews were found to be conducted at appropriate frequencies with sufficient depth for all departments.

The assessments reviewed were thorough and effective in identifying plant performance deficiencies, programmatic concerns, and improvement opportunities. On the basis of the interviews conducted, the inspectors did not identify any impediment to the establishment of a safety conscious work environment at Point Beach Nuclear Plant. Licensee staff was aware of and generally familiar with the CAP and other processes, including the Employee Concerns Program, through which concerns could be raised.

Although implementation of the CAP was determined to be generally effective, the inspectors identified several issues that were either minor in nature and/or represented potential weakness of the program.

NRC-Identified

and Self-Revealed Findings None.

Licensee-Identified Violations

None.

REPORT DETAILS

4OA2 Problem Identification and Resolution

This inspection constituted one biennial sample of Problem Identification and Resolution as defined by Inspection Procedure 71152, Problem Identification and Resolution.

Documents reviewed are listed in the Attachment to this report.

.1 Assessment of the Corrective Action Program (CAP) Effectiveness

a. Inspection Scope

The inspectors reviewed the procedures and processes that described the CAP at Point Beach Nuclear Plant to ensure, in part, that the requirements of 10 Code of Federal Regulations (CFR) Part 50, Appendix B, Criterion XVI, Corrective Action, were met.

The inspectors observed and evaluated the effectiveness of meetings related to the CAP, such as the Initial Screening Team meeting, the Management Review Committee meeting and the Corrective Action Review Board meeting. Selected licensee personnel were interviewed to assess their understanding of and their involvement in the CAP.

The inspectors reviewed selected condition reports across all seven Reactor Oversight Process cornerstones to determine if problems were being properly identified and entered into the CAP. The majority of the risk-informed samples of condition reports reviewed were issued after the last NRC Problem Identification and Resolution inspection completed in July of 2011. The inspectors also reviewed selected issues that were more than five years old.

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

The inspectors selected the gas turbine generator system to review in detail as a vertical slice sample based on input from the resident staff semi-annual trend review. The gas turbine generator system was a nonsafety-related, but risk significant, Maintenance Rule (a)(1) system. The gas turbine generator is allowed by Technical Specification to satisfy the Electrical Power Technical Specification Limiting Conditions of Operation (i.e. LCO 3.8.1.a). The gas turbine also has augmented quality functions for Station Blackout and Appendix R events. The primary purpose of this review was to determine whether the licensee was properly monitoring and evaluating the performance of this risk significant system. A 5-year review of the Maintenance Rule (a)(1) process was also performed to assess the licensees efforts in monitoring and correcting system performance issues. The team also assessed whether the licensee effectively implemented monitoring programs. The inspectors performed walkdowns, as needed, to verify the resolution of issues.

The inspectors selected the emergency preparedness alert and notification system (sirens) and the independent spent fuel storage installation security as vertical slice samples for review including performing system walkdowns.

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

b. Assessment

(1) Identification of Issues Based on the results of the inspection, the inspectors concluded that, in general, the licensee was effective in identifying issues at a low threshold and entering them into the CAP. The inspectors determined that problems were generally identified and captured in a complete and accurate manner in the CAP. The licensee appropriately screened issues from both the NRC and industry operating experience at an appropriate level and entered them into the CAP when applicable. The inspectors also noted that deficiencies were identified by external organizations (including the NRC) that had not been previously identified by licensee personnel. These deficiencies were subsequently entered into the CAP for resolution.

With respect to the threshold for initiation of condition reports, the inspectors noted instances where conditions were not captured historically in the CAP. The inspectors reviewed Procedure PI-AA-204, Condition Identification and Screening Process, which stated that the site utilized an expectation of when in doubt, fill it out to identify any unexpected or unwanted conditions, encouraging a low threshold for reporting. Based on this guidance, during system walkdowns, the inspectors questioned licensee staff about whether various conditions identified by the inspectors met the threshold for initiation of a condition report. The responses received from licensee personnel involved with the walkdowns confirmed the low threshold defined in their procedures.

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

The inspectors performed a five year extensive review of the gas turbine generator system. As part of this review, the inspectors interviewed the current and prior system engineers, reviewed a sample of gas turbine generator system health reports, condition reports, operating experience, apparent cause evaluations and a root cause evaluation.

The inspectors reviewed the CAP and work management system procedures that provided trending guidance. In addition, the inspectors walked down the gas turbine generator area to visually inspect recent gas turbine generator related modifications and to verify that identified concerns were tagged and entered into the CAP. The inspectors concluded that gas turbine generator related concerns were identified and entered into the CAP at a low threshold, and concerns were resolved in a timely manner commensurate with their safety significance. An observation related to the adequacy of a functionality assessment for the gas turbine generator was documented in Section 4OA2.1.b.(2).ii below.

Findings No findings were identified.

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

The inspectors determined that the Initial Screening Team meeting, the Management Review Committee meeting and the Corrective Action Review Board meeting were generally thorough and maintained a high standard for evaluation quality. Members of the Corrective Action Review Board discussed selected issues in sufficient detail and challenged presenters regarding their conclusions and recommendations.

The inspectors performed a detailed review of issues entered into the Maintenance Rule (a)(1) category covering approximately the past five years. The review included the longest standing (a)(1) system, the gas turbine generator and a recent (a)(1) entry, emergency lighting. The inspectors reviewed action plans approved by the expert panel, associated cause evaluations, Maintenance Rule evaluations, and condition reports.

The inspectors noted that the licensee generally showed no reluctance in placing structure, system, and components into Maintenance Rule (a)(1) status. Appropriate corrective actions to address the maintenance deficiencies were prescribed and completed. A detailed review of the structure, system, and components performance generally occurred before returning such structure, system and components to (a)(2)status.

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

In general, appropriate actions were assigned to correct the degraded or non-conforming condition.

However, the inspectors noted vulnerabilities and deficiencies in the licensees evaluations of some conditions. These vulnerabilities and deficiencies had the potential to lead to degraded or inoperable conditions not being recognized.

Observations Vulnerabilities in Licensees Condition Evaluations The inspectors found several instances where the licensees documentation lacked sufficient detail to address the extent of condition such that a technically competent reviewer could understand how the identified actions would correct the condition.

The inspectors concluded that this represented a failure to evaluate the condition as described in Procedure PI-AA-205, Condition Evaluation and Corrective Action, and that this impacted the licensees ability to identify adequate corrective actions. The inspectors identified the following condition reports as examples where the evaluation lacked sufficient detail:

• AR 1762546 - Security Observation - This condition evaluation lacked detail regarding the extent of condition, the fire areas/zones impacted, the fire round qualifications of individuals involved, and impact of the failures on the fire protection system.

• AR 1709409, Security Procedure Violation - This apparent cause evaluation did not document the timeliness deficiency identified regarding the reporting of the condition.

• AR 1801201, Improper Post Turnover Conducted - This condition evaluation did not evaluate the impact on the security plan.

• AR 1714146, Point Beach UE 11/27, Single Point Failure Issues - This condition report was closed to a root cause evaluation associated with another condition report and there was no documentation in support of this change.

• AR 1792071, 10 CFR 50.54(q) Description Did Not Match Actual Changes Made - This condition report lacked sufficient detail regarding the evaluation of the condition and impact on emergency preparedness reporting requirements.

• AR 1812176, Emergency Preparedness Needs Support to Be Successful -

This condition report lacked sufficient detail regarding the actions taken to close the issue.

In response to these observations, the licensee took immediate actions and provided additional information to address the underlying concerns. Additionally, the licensee initiated AR 1894494, 2013 PI&R - Condition Report Evaluation - Weak Documentation and assigned condition evaluations in the areas of Security and Emergency Preparedness.

Deficiencies in Gas Turbine Generator Functionality Assessments On February 8, 2013, the G-05 Gas Turbine Generator failed due to a flameout resulting from ice and snow ingestion during a snowstorm. The licensee initiated AR 1846509 to troubleshoot the failure. The gas turbine was successfully restarted soon after the snow storm had ended and the licensee concluded that the gas turbine was functional.

To address the functionality of the gas turbine during future severe weather, the licensee initiated AR 1847140, G-05 Functionality during Severe Weather. The shift manager initially requested a functionality assessment for the gas turbine generator. The inspectors questioned if the shift manager should have initially requested an operability determination (OD) for the gas turbine because Section 2.1 of the licensees OD procedure, EN-AA-203-1001, Operability Determinations/Functionality Assessments, Revision 9, stated that The OD process is used to assess the Operability of SSCs described in Technical Specifications. The gas turbine generator is described in Technical Specifications.

Section 8.9.1 of the licensees Final Safety Analysis Report stated that the gas turbine performed no safety-related functions but did perform some Appendix R functions and Station Blackout functions. Since the gas turbine is described in and used to satisfy Technical Specification Limiting Condition for Operation (i.e. TS LCO 3.8.1), the inspectors determined that the failure to follow procedure EN-AA-203-1001, Section 2.1 and initiate an OD was an NRC-identified performance deficiency. The inspector determined that the licensee should have initiated an OD and documented why the issue would be evaluated under a functionality assessment. This performance deficiency was considered minor because there was no safety consequences associated with the missing step in transitioning to a functionality assessment.

In addition, the assessment for the gas turbine generator functionality during severe weather was completed on February 21, 2013. The functionality assessment concluded that G-05 was functional for Station Blackout and loss of Transformer X03 scenarios during a heavy snow/high wind event, provided that the gas turbine generator was loaded to greater than 10 megawatts (MW). This loading would make the combustor section hotter and the generator would be immune to flameout during severe weather.

The functionality assessment also concluded that the gas turbine generator was functional but nonconforming for a specific Appendix R event during severe weather.

For this specific Appendix R event, the gas turbine generator could only be loaded to a maximum of 2.5 MW, which did not make the combustor section hot enough to prevent flameouts during severe weather. However, the assessment failed to specifically evaluate the impact of the generator tripping off due to a severe-weather-induced flameout during an Appendix R event.

Step 5.G

(4) of EN-AA-203-1001, Attachment 8, required documentation of the basis for functionality for each potential problem that existed. Therefore, the failure to evaluate the impact of the generator tripping offline during an Appendix R event was an NRC-identified performance deficiency. As a result of questions from the inspectors, the licensee evaluated the issue and concluded that the gas turbine generator could be restarted before any equipment damage would occur during an Appendix R event.

Therefore, the inspectors determined that the performance deficiency was minor because under the current conditions there had been no safety consequences associated with the missing documentation.

The licensee initiated AR 1893275 to document these discrepancies. The recommended actions of the condition report proposed communication of these lessons learned to operations and engineering personnel who request or perform operability determinations and functionality assessments. The licensee was in the process of installing a hood over the intake to prevent snow and rain from entering the gas turbine generator.

Findings No findings were identified.

(3) Effectiveness of Corrective Action Based on the results of the inspection, the inspectors concluded that the licensee was generally effective in addressing identified issues and the assigned corrective actions were generally appropriate. The licensee implemented corrective actions in a timely manner, commensurate with their safety significance, including an appropriate consideration of risk. Problems identified using root or apparent cause methodologies were resolved in accordance with the CAP procedural and regulatory requirements.

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

However, vulnerabilities were noted in the thoroughness of corrective actions.

Specifically, the licensees pre-inspection review identified several instances where corrective actions were closed inappropriately and that additional actions were needed to complete the closeout of the corrective actions. The inspectors determined these discrepancies were minor compliance issues with the CAP procedures and the licensee had taken actions to address these issues.

The inspectors also identified that there were 630 open corrective action items at the time of the inspection. More than 60 of these items were greater than three years old.

The inspectors reviewed a sample of these items and verified that the condition reports were evaluated and actions assigned appropriately. The inspectors determined that most of the remaining actions were minor non-conformances or enhancements and the due dates for the actions had been extended a number of times due to resource limitations or other emergent issues. For those corrective actions that were safety significant, the inspectors verified that the due dates were reasonable and the licensee had appropriate compensatory actions in place.

The inspectors regarded the aging corrective action issue as an opportunity for improvement. While the total number of outstanding actions was considered manageable, they could potentially affect the licensees focus on the more important safety issues and complicate resource utilization.

Observations Vulnerability in Implementation of Corrective Actions With respect to the licensees timeliness of corrective actions, the inspectors noted that the time frame between when a condition was identified until the time of implementation of corrective action could be as long as 165 days (30 or 45 days for evaluation and 120 days for implementation of corrective actions following evaluation) and could be longer if extensions were granted. While the procedure allowed this amount of time and extensions with management approval, the inspectors were concerned that this amount of time could cause the licensee to be vulnerable to repeat issues in the period before the final corrective action was implemented. The inspectors identified the following as an example:

• AR 1785395, NRC Cross-Cut to H.2(c), Documentation, Adverse Trend -

This condition report was initiated on July 18, 2012, and the inspectors identified the date of completion for the final corrective actions was February 12, 2013 (206 days). The final corrective action was to identify and revise those programs controlling important procedures and processes to ensure a link between the procedures and site risk management procedures.

The inspectors noted that the licensee did not put an interim corrective action in place from July 2012 through February 2013. During this time period, the inspectors had identified a number of risk management related issues including one Non-Cited Violation (NCV 2012004-02) and three minor violations (AR 1847252, AR 1847635, and AR 1834675) for the licensees failure to monitor risk, as documented in the Integrated Inspection Report 2012004.

The inspectors reviewed Procedure PI-AA-204 and found that it defined an interim corrective action as an action taken to temporarily prevent the effects of a condition or make an event less likely to recur during the period when the condition is being evaluated and the final corrective actions are completed. The initial screening team is required by procedure to consider the need for interim corrective action. However, the procedure guidance is only provided for conditions that directly challenge the performance of a system. The inspectors determined that interim corrective actions may be beneficial to temporarily prevent the effects of a condition or to make an event less likely to recur during the period when the condition is being evaluated and the final corrective actions are completed. The inspectors concluded that the lack of guidance regarding interim barriers represented vulnerabilities and could impact the licensees evaluation of conditions.

Missed Opportunity to Address Design Deficiency of the Unit 2 Turbine Driven Auxiliary Feedwater Pump On June 21, 2007, the licensee observed moisture in the turbine outboard bearing oil for the 2P-29, Unit 2 turbine driven auxiliary feedwater pump. An operability determination was performed and determined that the pump was operable. The operability determination also established a water content level below 5000 parts per million (ppm)as a threshold for operability and required an oil sample and oil change after every pump run.

An overhaul of the turbine was completed on September 23, 2007, in an attempt to correct the water intrusion problem. An oil sample taken during the initial post maintenance test run showed a high water content of 20,040 ppm and a sample taken during a second post maintenance test run showed 56 ppm of water. The licensee attributed the high water content during the first run to initial break in of the gland seals and returned the pump to service.

The water content of an oil sample taken during the next surveillance test on November 1, 2007, exceeded the operability criterion of 5000 ppm. The licensee elected to run the pump to show that the 8-hr design basis mission time could be met. This was done as a compensatory measure every 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. The licensee later took the pump out of service for overhaul on November 13, 2007, and returned it to service with the normal moisture level in the turbine bearing oil. The licensee determined that this was a significant condition adverse to quality and performed a root cause evaluation, RCE 1331388, 2P-29 AFW Pump Moisture in Oil, for the issue. The licensee determined that the root causes of the issue were inadequate instructions in procedures and training for applying sealant and assembling the terry turbine. This resulted in a steam leak at the gland and turbine casing. The steam subsequently migrated into the lube oil system for the pump and raised the water content of the oil above its operability criterion. Corrective actions to prevent recurrence were prescribed to revise the applicable maintenance procedures and to conduct training for the maintenance technicians. However, the steam leaks from the terry turbine continued with moisture intrusion into the oil system although the magnitude was low enough that operability of the pump was maintained.

On May 18, 2010, during a quarterly surveillance, turbine casing joint steam leakage was discovered and a subsequent oil sample revealed a visually unacceptable sample result with high water content. The licensee analyzed the oil sample and found that the water content was below the 5000 ppm criterion. However, the licensee estimated that the water intrusion would exceed the 5000 ppm criterion if the pump were to run for 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> based on a conservatively assumed constant intrusion rate. Therefore, the licensee took the pump out of service for repair. The issue on past operability was reviewed by the resident inspectors as documented in the Integrated Inspection Report 2010003 and no finding was identified at the time. The licensee completed the repair and returned the pump to service on May 20, 2010. At that time, the licensee determined that this was only a condition adverse to quality but assigned a root cause evaluation to examine the issue. RCE 1389194, 2P-29-T Casing Leak Identified during IT-09A Initial Start, was completed on July 6, 2010, and concluded that the turbine casing steam leakage was due to the temporary axial and radial distortion in the turbine casing from the turbine and piping mounting configuration that did not adequately accommodate thermal growth.

This root cause evaluation further concluded that the licensee recognized that accommodation for proper thermal expansion of the turbine was required since 1987, but only a limited scope modification was made in the late 1980s to alleviate a series of bearing wipes. Subsequent to this time period, the licensee has documented a number of steam leaks, bearing issues, and moisture intrusion events. There were a total of six condition reports that documented elevated water content in oil between November 2007 and May 2010. The root cause evaluation stated that some of these events were evaluated through root cause and closed to specific actions to address deficiencies noted in those instances. The root cause evaluation also stated that an aggregate review of the history confirmed that the repeated events were related to information the licensee already had which confirmed that the original design turbines require modifications to account for thermal growth such that the turbine casing was not distorted. As a long term corrective action to prevent recurrence, the licensee determined that the turbine driven auxiliary feedwater pump turbine would be replaced.

In the interim, the licensee would monitor the oil content and perform repairs to maintain operability.

Since the completion of the 2010 root cause evaluation, the licensee has not resolved this issue. There were documented steam leaks and moisture in the lube oil system, however, these events had not resulted in inoperability of the auxiliary feedwater pump.

Due to vendor qualification issues and other process delays, the installation of the replacement Unit 2 turbine and all associated actions will not be completed until the U2R33 refueling outage in the spring of 2014.

Even though the licensee did not identify that thermal expansion was a contributing factor for the water intrusion in 2007, the inspectors concluded that the licensee would not have identified this cause until the sealant installation and training deficiencies were corrected. The relative contribution of the steam leak from each of these causes could not be quantified accurately. Given the magnitude of the water intrusion in 2010 was only a fraction of the intrusion identified in 2007, it was reasonable to conclude that the significant steam leak condition from 2007 did not reoccur. Therefore, no performance deficiency existed for the 2007 root cause evaluation. However, the inspectors determined that the licensee missed an opportunity in 2007 to address a known design deficiency. The root cause evaluation should be comprehensive and address all possible known deficiencies that could have resulted in the significant condition adverse to quality. Under different circumstances, thermal expansion might lead to a steam leak large enough to cause the pump to become inoperable. The licensee plans to correct this design deficiency with a replacement turbine.

Findings No findings were identified.

(4) Implementation of Corrective Actions Generated Since NRC 95001 Supplemental Inspection

a. Inspection Scope

The inspectors reviewed the 95001 supplemental inspection action items that were implemented and the effectiveness review that had been conducted since the completion of the supplemental inspection on March 8, 2013. This supplemental inspection was related to a White Emergency Preparedness finding that was documented in NRC Inspection Report 05000266/2012504; 05000301/2012504.

The supplemental inspection was documented in NRC Inspection Report 05000266/2013503; 05000301/2013503.

b. Assessment The inspectors reviewed AR 1757131, EX-12 - Potential Violation RSPS Degraded Function, and found that the associated corrective actions had been planned and implemented. Specifically, 21 of the 23 assigned corrective actions (approximately 91 percent) had been completed at the time of this inspection. There was one additional corrective action that had been completed since the time of the supplemental inspection.

The inspectors reviewed the completed corrective actions, the licensees quick hit assessment of the root cause evaluation corrective actions, and found them to be adequate. The remaining open corrective actions include effectiveness reviews of the protective action recommendation and 50.54(q) process, both due on December 20, 2013.

c. Findings

No findings were identified.

.2 Assessment of the Use of Operating Experience

a. Inspection Scope

The inspectors reviewed the licensees implementation of their operating experience program. Specifically, the inspectors reviewed the operating experience program implementing procedures, and completed evaluations of operating experience issues and events. The inspectors also observed meetings and daily activities for the use of operating experience information. The intent was to determine if the licensee was effectively integrating experience into the performance of daily activities, whether evaluations of issues were proper and conducted by qualified personnel, whether the program was sufficient to prevent future occurrences of previous industry events, and whether the licensee effectively used the information in developing departmental assessments and facility audits. The inspectors also assessed whether corrective actions, as a result of operating experience, were identified and implemented effectively and in a timely manner.

b. Assessment Based on the results of the inspection, the inspectors concluded that in general, operating experience was effectively utilized by the licensee. The inspectors observed that operating experience was discussed as part of the daily and pre-job briefings.

Industry operating experience was effectively disseminated across plant departments and no issues were identified during the inspectors review of licensee operating experience evaluations.

c. Findings

No findings were identified.

.3 Assessment of Self-Assessments and Audits

a. Inspection Scope

The inspectors reviewed selected Focused Self-Assessments, benchmarkings, Quick Hit self-assessments, and Nuclear Oversight audits, as well as the schedule of past and future assessments. The inspectors evaluated whether these audits and self-assessments were effectively managed, adequately covered the subject areas, and properly captured identified issues in the CAP. In addition, the inspectors interviewed licensee personnel regarding the implementation of the audit and self-assessment programs.

b. Assessment Based on the results of the inspection, the inspectors concluded that self-assessments and audits were generally accurate, thorough, and effective at identifying issues and enhancement opportunities at an appropriate threshold. The inspectors concluded that these audits and self-assessments were completed by personnel knowledgeable in the subject area. In many cases, these self-assessments and audits had identified numerous issues that were not previously recognized by the licensee. These issues were entered into condition reports as required by the CAP procedures. For example, nuclear oversight had identified issues that included aging of the reactor simulator software and inadequate thermal performance testing and analysis of heat exchangers.

The heat exchanger testing issue had been elevated to the fleet executive vice president and chief nuclear officer for resolution following the fleet quality assurance processes.

c. Findings

No findings were identified.

.4 Assessment of Safety Conscious Work Environment

a. Inspection Scope

The inspectors interviewed selected Point Beach Nuclear Plant personnel to determine if there were any indications that licensee personnel were reluctant to raise safety concerns, to either their management or the NRC, due to fear of retaliation. The inspectors reviewed selected Employee Concern Program activities to identify any emergent issues or potential trends. The inspectors also assessed the safety conscious work environment through a review of employee concern program implementing procedures, discussions with employee concern program manager, interviews with personnel from various departments, and reviews of condition reports. The licensees programs to publicize the CAP and employee concern program were also reviewed.

The inspectors reviewed licensees self-assessments and assessments by external organizations of safety culture to determine if there were any organizational issues or trends that could impact the licensees safety performance.

b. Assessment The inspectors did not identify any issues that suggested conditions were not conducive to the establishment and existence of a safety conscious work environment. Licensee staff was aware of and generally familiar with the CAP and other processes, including the employee concern program, through which concerns could be raised. In addition, a review of the types of issues in the employee concern program indicated that personnel were appropriately using the CAP and employee concern program to identify issues.

The staff also indicated that management had been supportive of the CAP by providing time and resources for employees to generate their own condition reports.

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

Some employees indicated a number of low level items were not being corrected in a timely manner. The inspectors determined that the timeliness of the planned corrective actions for the examples given were commensurate with their safety significance.

Various safety culture assessments had been performed by contractors, the licensees staff, and a nuclear plant owner/operators organization. The results indicated that there were no impediments to the identification of nuclear safety issues. In addition, the NextEra fleet procedure on safety culture created a Nuclear Safety Culture Team, made up of plant managers, to monitor safety culture at the site on a periodic basis (at least quarterly). The licensee had also initiated a Nuclear Safety Culture Improvement Team with plant staff membership to conduct surveys and evaluations and develop improvement actions on a routine basis. The Nuclear Safety Culture Improvement Team met monthly, issued minutes, and provided input to management on safety culture health and initiatives. The inspectors concluded that this group was actively engaged in the plant safety culture and could be effective in proactively addressing issues and initiating improvements.

c. Findings

No findings were identified.

4OA6 Management Meetings

a. Interim Exit Meeting On August 2, 2013, the inspectors presented the preliminary inspection results to Mr. L. Meyer, and other members of the licensee staff.

b. Exit Meeting On August 28, 2013, Mr. R. Ng provided the final inspection results to Ms. F. Hennessy via a teleconference. The licensee acknowledged the issues presented. Mr. Ng also confirmed that none of the potential report input discussed was considered proprietary.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

L. Meyer, Site Vice President

E. McCartney, Site Director

R. Baird, Acting Training Manager

F. Hennessy, Performance Improvement Manager

C. McMillan, Scheduling Manager

M. Millen, Licensing Manager

C. Mott, Chemistry Supervisor

J. Pruitt, Nuclear Oversight Manager

G. Strharsky, Emergency Preparedness Manager

C. Trezise, Engineering Director

G. Vickery, Acting Plant General Manager/Operations Manager

R. Welty, Radiation Protection Manager

Nuclear Regulatory Commission

P. Pelke, Acting Branch Chief, Branch 6, Division of Reactor Projects

D. Betancourt-Roldan, Acting Senior Resident Inspector

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

None

Closed

None

Discussed

None Attachment