IR 05000282/2012007

IR 05000282-12-007; IR 05000306-12-007 Prairie Island Nuclear Generating Plant, Units 1 and 2; NRC Biennial Problem Identification and Resolution Inspection Report

ML12269A253
Person / Time
Site:	Prairie Island
Issue date:	09/25/2012
From:	Kenneth Riemer NRC/RGN-III/DRP/B2
To:	Sorensen J Northern States Power Co
References
IR-12-007
Download: ML12269A253 (27)

Text

UNITED STATES ber 25, 2012

SUBJECT:

PRAIRIE ISLAND NUCLEAR GENERATING PLANT, UNITS 1 AND 2; NRC BIENNIAL PROBLEM IDENTIFICATION AND RESOLUTION INSPECTION REPORT 05000282/2012007; 05000306/2012007

Dear Mr. Sorensen:

On August 22, 2012, the U.S. Nuclear Regulatory Commission (NRC) completed a biennial team inspection of Problem Identification and Resolution at your Prairie Island Nuclear Generating Plant, Units 1 and 2. The enclosed inspection report documents the inspection findings which were discussed on August 22, 2012, with you and members of your staff.

This inspection was an examination of activities conducted under your license as they relate to the identification and resolution of problems, compliance with the Commission=s rules and regulations, and with the conditions of your operating license. Within these areas, the inspection involved selected examination of procedures and representative records, observations of activities, and interviews with personnel.

Overall, the corrective action program was considered functional, but there were significant challenges that reduced its overall efficacy. Most issues were properly evaluated, but there were examples of inconsistency and a lack of rigor, resulting in some issues being minimally reviewed and having more significant concerns that were not identified. Workers continued to identify issues, but were losing confidence in the program due to the large backlog of open items, recurrent plant events and continued management turnover. Although your staff was taking action to address these weaknesses, it was questionable whether these initiatives would be self-sustaining in the long term.

Based on the results of this inspection, no findings were identified. However, there were three Unresolved Items identified. The specifics of these items and the information needed to disposition them are discussed in the report. 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 Documents Access and Management System (ADAMS),

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

Sincerely,

/RA/

Kenneth Riemer, Chief Branch 2 Division of Reactor Projects Docket Nos. 50-282, 50-306, and 72-010 License Nos. DPR-42, DPR-60, and SNM-2506

Enclosure:

Inspection Report 05000282/2012007; 05000306/2012007 w/Attachment: Supplemental Information

REGION III==

Docket Nos: 50-282; 50-306;72-010 License Nos: DPR-42; DPR-60; SNM-2506 Report No: 05000282/2012007; 05000306/2012007 Licensee: Northern States Power Company, Minnesota Facility: Prairie Island Nuclear Generating Plant, Units 1 and 2 Location: Welch, MN Dates: July 23 through August 22, 2012 Inspectors: N. Shah, Project Engineer, Team Leader K. Stoedter, Senior Resident Inspector, Prairie Island D. McNeil, Senior Operating License Examiner E. Sanchez-Santiago, Engineering Inspector Approved by: K. Riemer, Chief Branch 2 Division of Reactor Projects Enclosure

TABLE OF CONTENTS REPORT DETIALS .................................................................................................................... 2 4. OTHER ACTIVITIES ................................................................................. 2 4OA2 Biennial Problem Identification and Resolution (71152B) .......................... 2 SUPPLEMENTAL INFORMATION............................................................................................. 1 KEY POINTS OF CONTACT ................................................................................................. 1 LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED ...................................................... 1 LIST OF DOCUMENTS REVIEWED ..................................................................................... 2 Enclosure

SUMMARY OF FINDINGS

Inspection Report 05000282;05000306/2012-007; 07/23/2012 - 8/10/2012; Prairie Island

Nuclear Generating Plant, Units 1 and 2; Routine Biennial Problem Identification and Resolution Inspection.

This report covers a 3 week period of announced baseline inspection by three regional inspectors and one senior resident inspector. The significance of most findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual Chapter 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. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NURE-1649, Reactor Oversight Process, Revision 4, dated December 2006.

Problem Identification and Resolution Although the Prairie Island corrective action program (CAP) was functional, there were a significant number of challenges that reduced its overall efficacy. Workers continued to identify issues at an appropriate threshold, but there was a significant number of issues that remained uncorrected. This growing backlog of legacy issues resulted in recurring events that significantly challenged current plant performance. Most items entered into the CAP were screened and prioritized in a timely manner using established criteria, but there were some examples of inconsistency and a lack of rigor in the screening process. Most issues were properly evaluated, but there were numerous examples where issues were minimally reviewed and more significant concerns were not identified. There were also examples where the inspectors questioned whether the safety significance of the issues was properly characterized.

Audits and self-assessments were performed at an appropriate frequency, but were generally less intrusive than those conducted by Nuclear Oversight, lessening their overall effectiveness.

Collectively, these issues resulted in declining confidence among workers that problems would be corrected.

Of particular concern, was the high rate of management turnover. This negatively impacted the licensees ability to maintain continuous improvement; to reinforce management expectations for CAP implementation; and to allow the line organization to effectively manage the workload and ensure that corrective actions were timely implemented.

In 2007 and 2009, the inspectors were critical of the corrective action program implementation based on observed deficiencies similar to those discussed above. The licensee subsequently initiated several improvement initiatives that had resulted in some improvement, as documented in the 2010 biennial problem identification and resolution inspection. However, as noted above, these improvements were not sustained and overall performance had declined. Although the licensee had identified these weaknesses and was taking additional action, the current improvement program was not yet fully implemented and effective.

NRC-Identified

and Self-Revealed Findings No findings were identified.

Licensee-Identified Violations

No violations were identified.

REPORT DETAILS

4OA2 Biennial Problem Identification and Resolution

The activities documented in Sections a. through d. constituted one biennial sample of problem identification and resolution as defined in Inspection Procedure (IP) 71152.

.1. Assessment of the Corrective Action Program Effectiveness

a. Inspection Scope

The inspectors reviewed the licensees Corrective Action Program (CAP) implementing procedures, interviewed personnel and attended CAP program meetings to assess the implementation of the CAP by site personnel.

The inspectors reviewed risk and safety significant issues in the licensees CAP program since the last NRC Problem Identification and Resolution (PI&R) inspection in 2010. The selection of issues ensured an adequate review of issues across NRC cornerstones. The inspectors used NRC generic communications, department self assessments, licensee audits, operating experience reports, and NRC documented findings as sources to select issues. Additionally, the inspectors reviewed Action Items (ARs), generated as a result of facility personnels performance in daily plant activities.

In addition, the inspectors reviewed ARs and a selection of completed investigations from the licensees various investigation methods, which included root causes, apparent causes, equipment apparent causes, and common cause investigations.

The review included all ARs (closed or open) documenting operator performance and fatigue related issues since June 2007; including any special audits, evaluations, action plans, etc. performed to address any associated significant issues or trends.

During the reviews, the inspectors evaluated the licensee staffs actions to comply with the facilitys corrective action program and 10 CFR Part 50, Appendix B, requirements.

Specifically, the inspectors evaluated if licensee personnel were identifying plant issues at the proper threshold, entering the plant issues into the CAP in a timely manner, and assigning the appropriate prioritization for resolution of the issues. The inspectors also evaluated whether the licensee staff assigned the appropriate investigation method to ensure the proper determination of root, apparent, and contributing causes. The inspectors also evaluated the timeliness and effectiveness of corrective actions for selected issue reports, completed investigations, and NRC findings, including Non-Cited Violations.

Assessment

(1) Effectiveness of Problem Identification Based on the information reviewed, the inspectors concluded that the threshold for initiating ARs was appropriate and was consistent with the plant procedural requirements. Issues were entered into the CAP at a low threshold and AR generation numbers were representative of a good problem identification ethic. Other safety conscious work environment (SCWE) indications such as surveys and interviews indicated willingness to identify issues and capture them in the CAP.

The inspectors identified an Unresolved Item (URI) regarding the failure to evaluate the minimum number of air receivers needed to ensure the operability of the emergency diesel generators. This URI is discussed below.

The inspectors identified several examples where ARs were not properly entered into the PASSPORT electronic database, which was used to track CAP related issues. The licensee documented this observation as AR 1347676.

Findings

.1 Unresolved item Regarding the Number of Air Receivers Required to be Greater

than 480 psig to Support Emergency Diesel Generator Operability

Introduction:

The inspectors identified an unresolved item due to differences between procedural guidance and the Updated Safety Analysis Report (USAR)regarding the number of emergency diesel generator (EDG) air receivers that needed to be pressurized to greater than 480 pounds per square inch gauge (psig) to support EDG operability.

Description:

On October 15, 2010, the licensee initiated AR 1254304 to document that the D6 EDG 2A starting air compressor relief valve (2EG-39-7)was leaking. This condition caused the pressure in the 2A starting air receiver to drop below 480 psig. Upon identifying this condition, the operators checked the operating status of the remaining three air receivers and determined that the 1A receiver was also less than 480 psig due to maintenance on the 1A starting air compressor. The operations crew immediately declared the D6 EDG inoperable since Alarm Response Procedures C50001, D5 Engine 1 Remote Alarm Responses and C60001, D6 Engine 1 Remote Alarm Responses, contained a note which stated that the pressure in three out of four air receivers must be greater than 480 psig to maintain EDG operability.

As part of this inspection, the inspectors reviewed the licensees evaluation and resolution of AR 1254304. The inspectors found that the 1A and 2A starting air compressors were repaired by the maintenance staff. Repairing the compressors allowed the pressure in the associated air receivers to be restored to normal operating levels. The inspectors also found that the licensee had assigned engineering personnel to evaluate whether the inability to maintain pressure in the 1A and 2A air receivers above 480 psig needed to be considered a maintenance rule functional failure. The inspectors reviewed the licensees completed maintenance rule evaluation and found that the condition of the 1A and 2A air receivers was not considered a functional failure due to information contained in the USAR which specified that only two of the four air receivers were needed for EDG operability. The inspectors were concerned by this conclusion since it was supported by information that conflicted with the alarm response procedures in effect in July 2010 and Procedure 2C20.7, D5/D6 Diesel Generators.

On August 3, 2012, the inspectors discussed the conflicting information with the licensee. The inspectors specifically discussed that the conflicting information could have resulted in one of the following conditions:

• Operations personnel declaring the D6 EDG inoperable due to overly conservative procedural guidance regarding air receiver pressure; or

• An incorrect maintenance rule evaluation may have been completed due to incorrect USAR information.

The licensee initiated AR 1347636 to document the inspectors concern. The licensee was evaluating the actual number of air receivers required to be pressurized to greater than 480 psig to support EDG operability at the conclusion of the inspection. As a result, this issue will be considered unresolved pending the inspectors review of the licensees evaluation and a determination regarding whether the licensee had appropriately evaluated the conditions described in AR 1254304 (URI 05000306/2012007-01: Number of Air Receivers Required to be Greater than 480 psig to Support EDG Operability).

(2) Effectiveness of Prioritization and Evaluation of Issues Assessment The overall performance in prioritization and evaluation of issues was acceptable, but this area still presented the most challenges to the CAP. AR screening was generally good and ownership was demonstrated by the line organization and the CAP team.

However, there continued to be problems with meeting CAP standards during the AR screening meetings. Although station management had increased observations of the screening meetings in order to provide feedback, the inspectors concluded that performance hadnt yet improved to the point where it could be sustained without continued management attention.

The licensee was applying a safety related (condition adverse to quality (CAQ)) versus non-safety related (not a condition adverse to quality (NCAQ)) screening criteria to assist with prioritization. Inspectors noted that this approach did not address the risk to plant operations and was not always accurately applied. Although all issues were addressed, the understanding of what constituted a Significant Condition Adverse to Quality (SCAQ) was limited; potentially resulting in some issues receiving an inappropriate level of oversight. Several licensee staff commented that this classification was only warranted for issues involving offsite radiological releases or having a significant effect on public safety. This meant that other issues that significantly affected plant performance would require a less rigorous evaluation. For example, the licensee had identified a potential substantive cross-cutting issue in the area of Problem Identification and Resolution, as CAQ instead of an SCAQ. A substantive cross-cutting issue was issued by the NRC after evidence of a significant decline in performance as indicated by an adverse trend (i.e., three or more) of similar NRC findings in a 12 month period. By not classifying this as an SCAQ, the licensee was potentially taking inappropriate action to address a significant breakdown in performance. This issue was documented as AR 1346177.

The inspectors noted that the station continued to focus on the symptoms rather than the causes when evaluating issues. Several examples were noted where questioning by inspectors had resulted in significant changes to the evaluations and, in some cases, NRC findings. One example was how the licensee addressed a question raised by the NRC resident inspector concerning the boot seals in the residual heat removal pits.

Specifically, the inspector noted that the boot seal was degraded and questioned the purpose of the seal. Initially, the licensee closed the issue by concluding that the seal was unnecessary for flood mitigation and then repaired the seal. However, further questioning by the NRC PI&R team, identified that the boot seal was a flood mitigation barrier and that compensatory measures may have been necessary during the period the seal was degraded. This issue was documented as AR 1347687 Root causes and Quality Assurance (QA) reports were generally acceptable, but there were some examples where these evaluations were neither sufficiently self-critical nor had a clearly defined problem statement. The licensee also had a common practice of rolling-up ARs into a single evaluation, which made it difficult to discern how the individual issues were addressed. The licensee had enhanced CAP oversight functions through the Plant Assessment Review Board which reviewed and graded CAP evaluations for all higher significance items, including root and apparent cause evaluations, and provided feedback to the staff. This enhanced oversight was a recent initiative; therefore it was too soon to determine if these improvements would be sustained long term.

The inspectors identified several issues with a root cause evaluation performed by the licensee after 34 senior management changes occurred between 2006 and 2011. This evaluation was documented as AR 1311305. The evaluation concluded that the turnover had not resulted in any actual consequence to the affected departments and that the causes were related to pay and benefits, high work load and quality of life issues. However, the inspectors noted that the overall conclusion was inconsistent with the results of other root and apparent causes, all of which identified management churn as a primary reason for continued poor CAP performance. Additionally, the evaluation did not address why the turnover only occurred at the Prairie Island station and not at other licensee facilities. The observations were included in the corrective actions assigned to AR 1311305.

Findings

.1 Unresolved Item for the Failure to Perform Maintenance Rule Evaluations After

Discovering Degraded Radiation Monitors

Introduction:

The inspectors identified an unresolved item regarding the failure to perform maintenance rule evaluations after discovering degraded conditions on four separate radiation monitors. Due to the missing evaluations, the inspectors were unable to determine whether the radiation monitor system had been appropriately evaluated under the maintenance rule as required by 10 CFR 50.65.

Description:

On July 15, 2010, the licensee initiated AR 1241216 to document that radiation monitor 1RM-48 was reading downscale. During the screening of this AR, the licensee assigned an individual to complete an apparent cause evaluation to determine the cause of the downscale condition. The licensee also assigned a maintenance rule evaluation to determine whether the condition of the radiation monitor constituted a maintenance rule functional failure as defined by 10 CFR 50.65.

Two days later, the licensee initiated AR 1241453 to document that several radiation monitors (including 1RM-48) were adversely impacted during the installation of a new R-11 radiation monitor. During the screening of this corrective action document, the licensee determined that an apparent cause evaluation was not needed since the poor design of the radiation monitor cabinetry, combined with the installation of new wires amongst older wires, had caused the adverse impacts. In addition, the screening team approved the cancellation of the apparent cause and maintenance rule evaluations assigned as part of AR 1241216 based upon the information contained in AR 1241453.

The inspectors reviewed the assignment cancellation information and agreed that the apparent cause evaluation was not needed. However, the maintenance rule evaluation was needed to determine whether additional maintenance rule related actions were required.

The inspectors questioned licensee personnel to determine whether a maintenance rule evaluation was completed for the equipment issue discussed in AR 1241216. The licensee informed the inspectors that the maintenance rule evaluation had not been completed. In addition, maintenance rule evaluations for the three other radiation monitors (2RM-48, 2R-71, and R-41) discussed in AR 1241453 were not performed. The licensee documented the failure to perform the maintenance rule evaluations as AR 1347349. The maintenance rule evaluations were ongoing at the conclusion of the inspection. As a result, this issue will be considered unresolved pending the inspectors review of the maintenance rule evaluations and a determination of whether the failures should have resulted in the radiation monitoring system being classified as an a(1)maintenance rule system (URI 05000282/2012007-03; 05000306/2012007-03:

Failure to Perform Maintenance Rule Evaluations After Discovering Degraded Radiation Monitors).

(3) Effectiveness of Corrective Actions Assessment The licensee resolved the majority of issues, but there remained a significant backlog of open issues that challenged the stations ability to manage current performance while addressing legacy issues. The station currently had a backlog of 78 open issues involving systems, structures and components considered operable, but degraded; 211 ARs that had been open for 2+ years; and 130 open high priority work items. These issues had resulted in workers having to live with long term deficiencies, resulting in a significant decline in worker morale. For example, during interviews with the inspectors, several plant operators felt that station management was unresponsive to their concerns about the large number of open operator burdens. In one case, the inspectors identified that a long standing concern regarding the functionality of the steam exclusion dampers and the associated operability of the safety-related equipment protected by those dampers had been open since 1998. This issue was considered a URI as discussed below.

The work load associated with the large backlog adversely affected the timely implementation of corrective actions and contributed to the common practice of addressing symptoms rather than evaluating causes.

Prairie Island continued to experience plant transients and equipment deficiencies due to the failure to adequately resolve previously identified problems. The resources needed to address these recurring issues have hindered the stations efforts to improve the CAP.

For example, in March 2012, the licensee lost reactor vessel level indication while lowering water in the reactor vessel. This was a significant event as the failure to maintain adequate water level in the reactor vessel could result in core damage due to insufficient cooling. The event resulted in part, from a failure to take corrective actions following a similar event in 2010. The 2012 event was investigated by the NRC and was documented in NRC Inspection Report 2012011.

There were several examples where Effectiveness Reviews were either inappropriate or were scheduled too early to be useful. This potentially allowed for recurrence of past events due to the mistaken belief that the underlying issues were corrected. The inspectors identified examples were these Reviews were scheduled prior to the completion of corrective actions and/or where similar problems recurred simply because a premature review erroneously concluded that the issues were resolved.

This observation was documented as AR 1347397.

Findings

.1 Unresolved Item Regarding the Design Basis of the Steam Exclusion Dampers.

Introduction:

An unresolved item was identified by the inspectors due to a lack of steam exclusion (SE) damper leakage design basis information, questions regarding the adequacy of SE damper testing, the functionality of the SE system, and the operability of safety related equipment protected by the dampers following a high energy line break (HELB) event.

Description:

In 1998 the licensee identified concerns regarding the ability of the SE system dampers to meet the leakage rate described in the USAR and the deterioration of non-metallic gears due to environmental conditions. These issues were documented as Nonconformance Reports 19981361 and 19981104.

The licensee initially planned to disposition the conditions as use as is conditions until a revised HELB analysis was completed and the SE dampers were replaced.

On October 7, 2009, the licensee initiated AR 1201589 to document that the activities needed to disposition the conditions described above as use as is conditions had not been completed. The licensee reviewed operability recommendations, engineering change records, and 10 CFR 50.59 screenings and evaluations and were unable to find any documents which evaluated the condition of the SE dampers as acceptable. The licensee screened AR 1201589 as a B level corrective action document. No apparent or root cause evaluation was assigned. The screening team concluded that the equipment conditions described in the 1998 Nonconformance Reports should be classified as operable but nonconforming conditions since they had not been corrected.

As part of this inspection, the inspectors reviewed the licensees resolution of AR 1201589. The inspectors identified the following:

• The licensee had not used the operability/functionality process described in Procedure FP-OP-OL-01, Operability/Functionality Program, when classifying the SE damper conditions as operable but nonconforming in 2009;

• The failure to use the process described in Procedure FP-OP-OL-01 resulted in someone other than the shift manager approving the operable but nonconforming decision;

• A formal operability recommendation did not exist; and

• The status of the SE system dampers should have been classified as functional but nonconforming rather than operable but nonconforming.

Corrective action document 1201589 also clarified that the SE damper leakage rate described in the USAR was a manufacturing specification rather than design basis information. The inspectors reviewed the most recent SE system health report and found that it also contained information which indicated that design basis information regarding the amount of SE damper leakage that could exist following a HELB did not exist. A large contributor to the lack of this design basis information was due to the fact that the 1998 HELB analysis remained incomplete as of August 10, 2012.

Based upon this information, the inspectors were concerned that the licensees monthly SE damper testing may not be adequately verifying the functionality of the SE system. The inspectors were also concerned that assumptions used in currently open operability recommendations regarding the heat up of the battery rooms, the auxiliary feedwater pump rooms, the D1 and D2 emergency diesel generator rooms and several other areas may not be adequate to ensure that the equipment in these rooms would remain capable of performing their specified safety functions following a HELB event. The licensee documented the inspectors concerns in ARs 1345879, 1347752, and 1349909. At the conclusion of the inspection, the shift manager had designated the SE dampers as functional but nonconforming due to the lack of design basis leakage criteria and recent SE damper test results which demonstrated that the dampers had appropriately closed when needed. However, the licensee was continuing to review the adequacy of the SE damper test and the assumptions in the currently open operability recommendations. As a result, this issue will be considered unresolved pending an inspection of the licensees review results (URI 05000282/2012007-03; 05000306/2012007-03: Lack of Design Basis Information for Steam Exclusion Damper Leakage).

.2. Assessment of the Use of Operating Experience

Inspection Scope The inspectors reviewed the licensees implementation of the facilitys Operating Experience (OE) program. Specifically, the inspectors reviewed implementing operating experience program procedures, attended CA program meetings to observe the use of OE information, reviewed completed evaluations of OE issues and events, and reviewed selected assessments of the OE program. The inspectors review was to determine whether the licensee was effectively integrating OE experience into the performance of daily activities, whether evaluations of issues were proper and conducted by qualified personnel, whether the licensees program was sufficient to prevent future occurrences of previous industry events, and whether the licensee effectively used the information in developing departmental assessments and facility audits. The inspectors also assessed if corrective actions, as a result of OE experience, were identified and effectively implemented.

Assessment In general, OE was effectively screened and corrective actions were assigned as appropriate. Root and apparent cause evaluations included discussions of OE, but there were some examples where the OE review was limited in focus. In addition, the inspectors found some examples where the OE evaluations were not of high quality despite having gone through supervisory review. Similar issues were also identified in the licensee self-assessments of the OE program and were being addressed in the CAP.

Although some corrective actions had been implemented, it was too early to determine their long term effectiveness.

Findings No findings were identified.

.3. Assessment of Self-Assessments and Audits

a. Inspection Scope

The inspectors assessed the licensee staffs ability to identify and enter issues into the CAP, prioritize and evaluate issues, and implement effective corrective actions through efforts from departmental self-assessments and NOS audits.

Assessment The inspectors concluded that departmental self-assessments were adequate and did identify issues at an appropriate threshold level. The assessments were completed by personnel knowledgeable in the subject area. By contrast, NOS assessments were typically more intrusive, critical and of better quality than the department self-assessments. In general, NOS was observed to be a more effective driver for CAP improvement than the department self-assessments. For example, the department self-assessment concluded that the CAP performance was improving and that corrective actions were effective at driving change. The NOS audit also noted that the CAP was improving, but identified significant challenges to CAP performance; NOS also questioned whether the observed improvements were self-sustaining. Overall, the NOS observations were more in line with the NRC inspection conclusions than the department self-assessments.

Findings No findings were identified.

.4 Assessment of Safety Conscious Work Environment

a. Inspection Scope

The inspectors assessed the licensees safety conscious work environment by reviewing the facilitys employee concerns program (ECP) implementing procedures, postings for maintaining employee awareness of the ECP program, discussions with the ECP coordinator, interviews with personnel from various departments, and reviews of ECP issue reports. The inspectors also reviewed the implementing procedures for the Differing Professional Opinions (DPO) program and the results of DPOs generated over the previous 2 years.

The inspectors reviewed the licensees safety culture policy statements and the results of safety culture assessments performed within the last 2 years. The inspectors also interviewed employees from various departments to assess their willingness to raise nuclear safety issues. The individuals were selected to provide a cross-section across the various departments at the site. In addition to assessing the willingness to raise nuclear safety issues, the interviews also addressed the changes in the CAP and plant environment over the past 2 years. Other items discussed included:

• knowledge and understanding of the program;

• effectiveness and efficiency of the program;

• willingness to use the program;

• managements support of the program;

• feedback on issues raised; and

• ease of input to the system.

Assessment The licensee maintains an accessible, functioning ECP that is generally well regarded by plant employees. Issues identified through the program were generally appropriately resolved and there were no significant trends noted. The DPO process was also well regarded, although not as commonly used as the ECP.

Employees were generally free to raise issues without fear of retaliation. During interviews, workers stated that they felt it was important to raise issues and felt free to do so. The process was not seen as cumbersome and was generally supported by management.

However, workers were losing confidence in the ability of the CAP to resolve issues The continued high backlog, recurrence of past events and high workload have left many workers feeling that long standing issues would not always be resolved in a timely manner. This was supported by statements made during interviews with the inspectors and the results of licensee safety culture assessments.

Additionally, continued management churn has degraded worker confidence in the CAP, hampered station efforts to maintain sustained CAP improvement and adversely affected the ability of the line organization to ensure that management expectations were met. This conclusion was based on the aggregate review of root and apparent cause evaluations and the consensus of workers during interviews with the inspectors.

Overall the inspectors concluded that while the safety culture was currently adequate, absent sustained long term improvement, workers may eventually lose confidence in the CAP and stop raising issues.

Findings No findings were identified.

4OA6 Management Meetings

Exit Meetings Summary On August 22, 2012, the inspectors presented the inspection results to J. Molden and other members of the licensee staff. The licensee acknowledged the issues presented.

The inspectors confirmed that none of the potential report input discussed was considered proprietary.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

T. Allen, Site Engineering Manager

P. Anderson, Corporate Director, Regulatory Affairs

B. Boyer, Radiation Protection Manager

H. Butterworth, Director, Corporate Functional Area Management

K. Davison, Director of Site Operations

P. Huffman, Site Engineering Director

A. Khanifar, Corporate Vice-President, Engineering

J. Lash, Nuclear Oversight Manager

P. Lindburg, Design Engineering Manager

J. Molden, Site Vice PresidentPrairie Island

T. OConner, Corporate Vice President of Engineering and Nuclear Regulatory Compliance

and Licensing

K. Petersen, Business Support Manager

D. Potter, Programs Engineering Manager

J. Ruttar, Operations Manager

Nuclear Regulatory Commission

G. Shear, Acting Director, Division of Reactor Projects, Region III

K. Riemer, Chief, Reactor Branch 2, Division of Reactor Projects, Region III

B. Kemker, Senior Resident Inspector, Clinton

S. Thomas, Senior Resident Inspector, Monticello

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

05000306/2012007-01 URI Number of Air Receivers Required to be Greater than 480 psig to Support EDG Operability

05000282/2012007-02; URI Failure to Perform Maintenance Rule Evaluations After

05000306/2012007-02 Discovering Degraded Radiation Monitors

05000306/2012007-03; URI Lack of Design Basis Information for Steam Exclusion

05000306/2012007-03 Damper Leakage Closed and

Discussed

None.

Attachment