IR 05000282/2014007

IR 05000282-14-007; 05000306-14-007; 06/09/14 - 06/27/14; Prairie Island Nuclear Generating Plant, Units 1 and 2; Biennial Problem Identification and Resolution Inspection (Pi&R)

ML14218A268
Person / Time
Site:	Prairie Island
Issue date:	08/06/2014
From:	Kenneth Riemer Division Reactor Projects III
To:	Davison K Northern States Power Co
References
IR-14-007
Download: ML14218A268 (40)

Text

UNITED STATES ust 6, 2014

SUBJECT:

PRAIRIE ISLAND NUCLEAR GENERATING PLANT, UNITS 1 AND 2; NRC BIENNIAL PROBLEM IDENTIFICATION AND RESOLUTION INSPECTION REPORT 05000282/2014007; 05000306/2014007

Dear Mr. Davison:

On June 27, 2014, the U.S. Nuclear Regulatory Commission (NRC) completed a Problem Identification and Resolution (PI&R) biennial inspection at your Prairie Island Nuclear Generating Plant, Units 1 and 2. The NRC inspection team discussed the results of this inspection with you and other members of your staff, and documented the results of this inspection in the enclosed report.

The inspection was an examination of activities conducted under your license as they relate to PI&R, compliance with the Commissions rules and regulations, and with the conditions of your license. Within these areas, the inspection involved examination of selected procedures and representative records, observations of activities, and interviews with personnel.

On the basis of the samples selected for review, the inspectors concluded that the corrective action program (CAP) was functioning, but several concerns remained in the areas of problem identification, evaluation, and resolution of issues. The inspectors determined that although some progress had been made in the licensees implementation of the CAP, the stations inability to clearly improve upon issues noted from the 2012 biennial PI&R inspection and other prior inspections and assessments, was of particular concern. Many of the NRCs concerns from prior assessments of the CAP continued to apply as evidenced by the findings and observations identified during this inspection. Additionally, while varying levels of improvement were made in the areas of evaluation and resolution of issues, a decline in the area of effectiveness of problem identification was apparent.

The inspectors noted recent CAP improvement initiatives; however, due to the relatively recent and ongoing implementation of these initiatives, the inspectors could not assess their adequacy or effectiveness during this inspection. Overall, the inspectors concluded that licensee management understood the site challenges associated with improving CAP implementation, but considering the long history of CAP concerns, the inspectors noted a lack of urgency to correct these concerns. Based on the results of this inspection, five NRC-identified findings of very low safety significance (Green) were identified during this inspection. All findings were determined to involve violations of NRC requirements, and one finding was determined to be a Severity Level IV violation under the traditional enforcement process. 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 violation or significance of the 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 the Prairie Island Nuclear Generating Plant.

If you disagree with any 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 the Prairie Island Nuclear Generating Plant.

In accordance with Title 10 of the Code of Federal Regulations 2.390, Public Inspections, Exemptions, Requests for Withholding, 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).

ADAMS is 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:

IR 05000282/2014007; 05000306/2014007 w/Attachment: Supplemental Information

REGION III==

Docket Nos: 50-282; 50-306;72-010 License Nos: DPR-42; DPR-60; SNM-2506 Report No: 05000282/2014007; 05000306/2014007 Licensee: Northern States Power Company, Minnesota Facility: Prairie Island Nuclear Generating Plant, Units 1 and 2 Location: Welch, MN Dates: June 9-27, 2014 Inspectors: L. Haeg, Senior Resident Inspector, Duane Arnold, Team Lead M. Holmberg, Senior Reactor Inspector S. Sheldon, Senior Reactor Inspector P. LaFlamme, Resident Inspector, Prairie Island Approved by: Kenneth Riemer, Chief Branch 2 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

Inspection Report 05000282/2014007; 05000306/2014007; 06/09/14-06/27/14; Prairie Island

Nuclear Generating Plant, Units 1 and 2; Biennial Problem Identification and Resolution Inspection (PI&R).

This report covers a 3 week period of announced baseline inspection by one senior resident inspector, two region-based inspectors, and one resident inspector. Five Green findings were identified by the inspectors. The findings were considered non-cited violations of NRC regulations, and one finding was determined to be a Severity Level IV under the traditional enforcement process. 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. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 5, dated February 2014.

Problem Identification and Resolution On the basis of the samples selected for review, the inspectors concluded that the corrective action program (CAP) at Prairie Island was functioning, but several concerns remained in the areas of PI&R of issues. The inspectors determined that although some progress had been made in the implementation of the CAP, the stations inability to clearly improve upon issues noted from the 2012 biennial PI&R inspection and other prior inspections and assessments, was of particular concern. Many of the NRCs concerns from prior assessments of the CAP continued to apply as evidenced by the findings and observations identified during this inspection. In particular, the lack of stability in CAP leadership and consistent accountability for implementing CAP requirements contributed to inconsistencies in the rigor by which issues were evaluated and corrected.

The inspectors noted recent initiatives such as the Prairie Island CAP Deep Dive review and Performance Assessment Excellence Plan; however, due to the relatively recent and ongoing implementation of these initiatives, the inspectors could not assess their adequacy or effectiveness during this inspection. Further, it appeared that frequent changes in CAP improvement initiatives to address long-standing issues contributed to the inability to make notable gains in CAP performance. Overall, the inspectors concluded that licensee management understood the site challenges associated with improving CAP implementation, but considering the long history of CAP concerns, the inspectors were troubled by the lack of urgency to correct these concerns.

NRC-Identified

and Self-Revealed Findings

Cornerstone: Initiating Events

• Severity Level IV. The inspectors identified a Severity Level IV NCV of Title 10 CFR 50.71(e), Periodic Update of the Final Safety Analysis Report, and an associated Green finding for the licensees failure to update the Updated Safety Analysis Report (USAR) with a complete list of pressure isolation valves (PIVs) and periodic acceptance test requirements that had been reported to the Commission. Specifically, the licensee did not update Prairie Island Updated Safety Analysis (USAR) Section 4.6.1.2.1 Pressure Isolation Valves to include all PIVs and their associated test requirements.

The licensee entered this issue into the CAP and initiated actions to change the USAR to incorporate the complete list of PIVs.

The inspectors determined that the licensees failure to update the USAR with a complete list of PIVs and periodic acceptance test requirements and report the update to the Commission was a performance deficiency. The performance deficiency was determined to be more than minor in accordance with IMC 0612, "Power Reactor Inspection Reports," Appendix B, "Issue Screening," because, if left uncorrected the performance deficiency would have the potential to lead to a more significant safety concern. Additionally, the failure to include all PIVs in the USAR was more than minor because it was associated with the Initiating Event Cornerstone attribute of Equipment Performance and adversely affected the Cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions. The inspectors utilized IMC 0609, Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings, and IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, and determined that the finding screened as very low safety significance (Green) since the inspectors answered No to the Loss Coolant Accident of Initiators questions in Exhibit 1, Section A, Initiating Events Screening Questions. In accordance with Section 6.1.d.3 of the NRC Enforcement Policy, this violation was also categorized as Severity Level IV because the licensees failure to update the USAR as required by 10 CFR 50.71(e) had not yet resulted in any unacceptable change to the facility or procedures. The inspectors determined that the performance characteristic of the finding that was the most significant causal factor of the performance deficiency was associated with the cross-cutting aspect of Human Performance, Documentation, and involving the organization creating and maintaining complete, accurate, and up-to-date documentation. [H.7] (Section 4OA2.1b.(2))

Cornerstone: Mitigating Systems

Green.

The inspectors identified a finding of very low safety significance and non-cited violation of Title 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures and Drawings, for the licensees failure to accomplish FP-PA-ARP-01, CAP Action Request Process, to notify the shift manager of an operability/reportability concern and initiate a CAP for past periods of plant operation with a cooling water (CL) system strainer isolated. Specifically, with a CL header strainer isolated, a seismic event could lead to operation of the remaining CL strainer with excessive flow (e.g., outside analyzed limits) and adversely affect safety-related components cooled by the CL system. The licensee entered this issue into the CAP and initiated actions to evaluate past periods of operation with isolated CL strainers.

The inspectors determined that the licensees failure to accomplish procedure FP-PA-ARP-01 was a performance deficiency. The performance deficiency was determined to be more than minor in accordance with IMC 0612, "Power Reactor Inspection Reports," Appendix B, "Issue Screening," because, if left uncorrected the performance deficiency would have the potential to lead to a more significant safety concern. Additionally, the performance deficiency was also determined to be more than minor because it was associated with the Mitigating Systems Cornerstone attribute of design control and adversely affected the Cornerstone objective of ensuring the availability, reliability, and capability of mitigating systems to respond to initiating events.

The inspectors utilized IMC 0609, Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings, and IMC 0609, Appendix A, The

Significance Determination Process For Findings At-Power. The inspectors answered Yes to Question 2 of Section A of Exhibit 2, Mitigating Systems Screening Questions, since the CL system may not have been able to perform its design cooling functions during past periods of operation with one CL header strainer isolated. Therefore, the finding required a detailed risk evaluation which had been previously completed by a Senior Reactor Analyst (SRA) for the original finding (NCV 05000282/2013007-02; 05000306/2013007-02). Specifically, the SRA had previously determined that the bounding core damage frequency for this issue was 1.9E-7/yr. and concluded the total risk increase to the plant due to this finding was of very low risk significance (Green).

The inspectors determined that the performance characteristic of the finding that was the most significant causal factor of the performance deficiency was associated with the cross-cutting aspect of Human Performance, Consistent Process, and involving individuals using a consistent, systematic approach to make decisions. Specifically, the licensee failed to use the CAP process, in evaluation of the past operability and reportability of the CL system with the CL system strainers isolated. [H.13]

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

Green.

The inspectors identified a finding of very low safety significance and non-cited violation of Title 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures and Drawings, for the licensees failure to prescribe a procedure appropriate to the circumstances with respect to the identification of a significant condition adverse to quality (SCAQ). Specifically, FP-PA-ARP-01, CAP Action Request Process, provided an overly restrictive definition of what constituted a SCAQ. Consequently, the licensee staff did not identify a failed residual heat removal (RHR) pump shaft as a SCAQ. The licensee entered this issue into the CAP and initiated actions to establish compensatory measures for screening action requests (ARs) until this issue was corrected.

The inspectors determined that the licensees failure prescribe a procedure appropriate to the circumstances under FP-PA-ARP-01 was a performance deficiency. The performance deficiency was determined to be more than minor in accordance with IMC 0612, "Power Reactor Inspection Reports," Appendix B, "Issue Screening," because, if left uncorrected the performance deficiency would have the potential to lead to a more significant safety concern. Although, this issue could potentially affect each of the Reactor Safety Cornerstones, the inspectors elected to evaluate this issue under the Mitigating Systems Cornerstone because of the actual example identified associated with the failed Unit 2 RHR pump shaft. The inspectors utilized IMC 0609, Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings, and IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, and determined that the finding screened as very low safety significance (Green) since the inspectors answered No to each of the questions in Exhibit 2,

Section A, Mitigating Systems Screening Questions. The inspectors determined that the performance characteristic of the finding that was the most significant causal factor of the performance deficiency was associated with the cross-cutting aspect of Problem Identification and Resolution, Self-Assessment, and involving the organization routinely conducting self-critical and objective assessments of its programs and practices.

Specifically, the failure to identify the overly restrictive definition of SCAQ during previous audits of the CAP was caused by an insufficiently self-critical audit focus. [P.6]

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

Cornerstone: Miscellaneous

Green.

The inspectors identified a finding of very low safety significance and non-cited violation of Title 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures and Drawings, for the licensees failure to accomplish FP-PA-ARP-01, CAP Action Request Process. Specifically, the inspectors identified three recent instances where additional questioning by NRC inspectors was required prior to CAP ARs being generated for conditions adverse to quality. As a result, conditions that rendered the 23 Fan Coil Unit (FCU) and the 13 FCU inlet Motor Operated Valve (MOV) inoperable, and identification of additional boric acid deposits on the 21 Reactor Coolant Pump (RCP)support structure, were not evaluated in a timely and effective manner. The licensee entered each of these instances into the CAP individually and collectively to determine the necessary actions to ensure identified conditions adverse to quality are entered into the CAP.

The inspectors determined that the failure to properly accomplish FP-PA-ARP-01 was a performance deficiency. The performance deficiency was determined to be more than minor in accordance with IMC 0612, Power Reactor Inspection Reports, Appendix B,

Issue Screening, because, if left uncorrected the performance deficiency would have the potential to lead to a more significant safety concern. Because all three instances discussed above qualitatively impacted the containment system, the finding is associated with the Barrier Integrity Cornerstone. The inspectors utilized IMC 0609,

Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings, and concluded that this findings significance was best characterized by using Appendix M of IMC 0609, Significance Determination Process Using Qualitative Criteria. Based upon the fact that the three instances discussed above did not rise to a level of greater than very low safety significance, the inspectors determined that this issue was best characterized as having very low safety significance (Green). The inspectors determined that the performance characteristic of the finding that was the most significant causal factor of the performance deficiency was associated with the cross-cutting aspect of Problem Identification and Resolution, and involving the organization implementing a CAP with a low threshold for identifying issues.

Specifically, the licensee did not implement the corrective action program at an appropriate threshold for identifying issues to ensure that conditions adverse to quality were addressed in a timely manner. [P.1] (Section 4OA2.1b.(1))

Green.

The inspectors identified a finding of very low safety significance and non-cited violation of Title 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures and Drawings for the failure to accomplish Attachment 14, CAP to External Process Interface, of procedure FP-PA-ARP-01, CAP Action Request Process. Specifically, the inspectors identified three examples where severity level C CAP actions were closed to processes outside the CAP, and then subsequently cancelled without appropriate justification or documentation. The licensee entered this issue into the CAP and initiated actions to develop barriers within the CAP processes.

The inspectors determined that the licensees failure to accomplish procedure FP-PA-ARP-01 was a performance deficiency. The performance deficiency was determined to be more than minor in accordance with IMC 0612, "Power Reactor Inspection Reports," Appendix B, "Issue Screening," because, if left uncorrected it would have the potential to lead to a more significant safety concern. The inspectors utilized IMC 0609, Significance Determination Process, Attachment 0609.04, Initial

Characterization of Findings, and concluded that because the programmatic deficiency potentially affected all NRC cornerstones, the significance was best characterized by using IMC 0609, Appendix M Significance Determination Process Using Qualitative Criteria. Based upon the fact that the examples identified did not rise to a level of greater than very low safety significance, the inspectors determined that this issue was best characterized as having very low safety significance (Green). The inspectors determined that the performance characteristic of the finding that was the most significant causal factor of the performance deficiency was associated with the cross-cutting aspect of Problem Identification and Resolution, and involving the organization taking effective corrective actions to address issues in a timely manner commensurate with their safety significance. Specifically, following the realization in April of 2013 of the potential flaws in the CAP processes to allow inappropriate cancellations of C severity level CAPs after being closed to the non-CAP PCR process, the station failed to correct the vulnerabilities that also existed for other non-CAP processes. [P.3] (Section 4OA2.1b.(3))

Licensee-Identified Violations

No violations were identified.

REPORT DETAILS

4OA2 Problem Identification and Resolution

The activities documented in Sections

.1 through .4 constituted one biennial sample of

Problem Identification and Resolution (PI&R) 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 and attended CAP meetings to assess the implementation of the program by site personnel. The inspectors also interviewed a number of licensee staff in several departments, including nuclear oversight, operations, maintenance, security, chemistry, and radiation protection, to gain insights on the CAP implementation.

The inspectors reviewed risk and safety significant issues in the licensees CAP since the last NRC biennial PI&R inspection in August of 2012. The selection of issues ensured an adequate review of issues across NRC cornerstones. The inspectors used issues identified through NRC generic communications, self-assessments, licensee audits, operating experience (OE) reports, and NRC documented findings as sources to select issues. Additionally, the inspectors reviewed CAP action requests (ARs)generated as a result of facility personnels performance in daily plant activities. In addition, the inspectors reviewed a selection of completed investigations from the licensees various investigation methods, which included root cause, apparent cause, equipment cause, and common cause evaluations.

The inspectors selected several high risk systems, which included the emergency diesel generator (EDG) and electrical switchgear systems, to review in detail. The inspectors review was to determine whether the licensee staff were properly monitoring and evaluating the performance of these systems through effective implementation of station monitoring programs. A 5 year review was also undertaken to assess the licensee staffs efforts in monitoring for system degradation due to aging aspects. The inspectors also performed partial system walk downs.

During the reviews, the inspectors determined whether the licensee staffs actions were in compliance with the facilitys corrective action program and Title 10 CFR Part 50, Appendix B requirements. Specifically, the inspectors determined if licensee personnel were identifying plant issues at the proper threshold, entering the plant issues into the stations CAP in a timely manner, and assigning the appropriate prioritization for resolution of the issues. The inspectors also determined 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 (NCVs).

Assessment

(1) Effectiveness of Problem Identification 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 NRC generic communications and industry OE at an appropriate level and entered them into the CAP when applicable. The inspectors also noted that deficiencies that were identified by external organizations (including the NRC) that had not been previously identified by licensee personnel were entered into the CAP for resolution.

Workers were familiar with the CAP and felt comfortable raising concerns. This was evident by the large number of CAP items generated annually; which were reasonably distributed across the various departments. However, considering the issues identified during the inspection, as well as insights from other assessments and observations at Prairie Island, timely and consistent use of the CAP to document issues appears to have declined since the 2012 PI&R inspection results.

The inspectors also identified concerns with some items assigned an apparent cause evaluation (ACE) versus a root cause evaluation (RCE). The 2012 biennial PI&R report noted examples where the characterization of some safety significant issues was questionable. The 2014 biennial PI&R inspection team noted that the CAP procedure definition of what constituted a significant condition adverse to quality (SCAQ) was different from the definition in the Prairie Island Quality Assurance Topical Report (QATR) and the committed 1994 Edition of American Society of Mechanical Engineers (ASME) NQA-01, Quality Assurance Requirements for Nuclear Facility Applications.

Because of this, the team questioned some instances where the AR severity level assigned may have been incorrect and non-conservative. Based on the finding discussed below, the station was vulnerable from an extent of condition standpoint where the appropriate level of evaluation may not have been performed and/or the appropriate preventative measures may not have been taken.

The station recently performed a CAP deep dive assessment that identified several gaps related to ongoing issues with CAP initiation delays and thresholds, management reinforcement of CAP standards, and poor documentation of actions. Although the team noted several examples during their review that aligned with the deep dive assessment gaps, the team did not assess the adequacy of current plans for improvement due to their ongoing or in-progress status. Refer to Section 4OA2.1(2)a below for additional information.

The inspectors performed a five year extensive review of the EDG and electrical switchgear systems. As part of this review, the inspectors interviewed the system engineer, reviewed a sample of system CAP ARs, OE, and causal evaluations. The inspectors reviewed the CAP procedures that provided trending guidance and walked down various portions of the systems to visually inspect equipment condition. The inspectors concluded that system-related concerns were identified and entered into the CAP at a low threshold.

b. Findings

Failure to Document Conditions Adverse to Quality in the Corrective Action Program

Introduction:

The inspectors identified a Green finding and NCV of Title 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures and Drawings, for the licensees failure to properly implement FP-PA-ARP-01, CAP Action Request Process.

Specifically, the inspectors identified three recent instances where additional questioning by NRC inspectors was required prior to CAP ARs being generated for conditions adverse to quality. As a result, conditions that rendered the 23 FCU and 13 FCU inlet Motor Operated Valve (MOV) inoperable, and identification of additional boric acid deposits on the 21 RCP support structure, were not evaluated in a timely and effective manner.

Description:

On three separate occasions, the inspectors identified instances where the licensee failed to generate ARs in accordance with FP-PA-ARP-01, each requiring subsequent evaluation:

• On April 17, 2014, while observing a post-maintenance test pre-job brief on the 13 FCU inlet MOV, the inspectors noted that the reactor operator self-identified that the Unit 1 operations crew should have entered Technical Specification (TS) 3.6.3 upon energizing the MOV actuator which had occurred prior to the pre-job brief.

Consequently, Unit 1 had been in an unplanned TS Limiting Condition for Operation (LCO) for approximately 90 minutes. Per shift manager review, a TS LCO entry was made to coincide with the time electrical power had been restored to the MOV. The following day during control room log review, the inspectors noted that the log entry had not been entered as a late entry and the unplanned LCO time had not been documented. As a result, no CAP AR was generated to document the occurrence.

The following week, during shift turnover, the inspectors observed the shift manager brief the new oncoming shift crew that the operations department had not experienced an unplanned LCO unknowingly for a couple of years. The inspectors then presented the previous weeks observation to the shift manager and AR 01428226 was generated regarding this concern on April 24, 2014.

• On May 18, 2014, following a planned Unit 2 shutdown to Mode 3 to correct improper drainage on a section of piping between the 21 RCP number 3 seal and the reactor coolant drain tank; the inspectors observed water on the floor near the 23 FCUs northeast face during a containment walk down. The inspectors reported the water to outage control center (OCC) personnel at approximately 9:30 p.m. The OCC logged the inspectors observation but did not initiate an AR. On May 19, 2014, during the 6:00 a.m. shift turnover briefing, the inspectors again inquired if any actions had been taken to evaluate the water on the floor in containment. The OCC informed the inspectors that the water was evaluated to be condensation and stated a chemistry sample was not needed. Additionally, the OCC was unable to provide an evaluation and did not initiate an AR. At approximately 10:30 a.m., while performing an additional containment walk down, the inspectors challenged the system engineer as to why a chemistry sample had not been performed. The system engineer then communicated the inspectors observation to the OCC and a chemistry sample was performed at 11:04 a.m. without generating an AR. At 12:25 p.m., chemistry technicians confirmed the contents of the water sample as cooling water (river water) and operations then declared the 23 FCU and the Unit 2 containment inoperable at 12:36 p.m. due to the cooling water leakage. The licensee generated AR 01431287 on May 19, 2014.

• On May 18, 2014, the inspectors observed a discussion between a system engineer and OCC personnel regarding the possible presence of boric acid underneath insulation for a 21 RCP tie rod. Following this observation, the inspectors believed that the insulation would be removed and an inspection would be performed to verify that the boric acid had not adversely impacted the tie rods structural integrity. On May 19, 2014, the inspectors requested a copy of the boric acid inspection and evaluation. The inspectors determined that the boric acid evaluation was generically written and failed to mention specific tie rod inspection results. Subsequent discussions with operations revealed that the operations department was unaware of the tie rod issue because an AR had not been issued. The licensee subsequently removed the insulation, performed the inspection, and documented the specific inspection results in AR 01431342.

The inspectors noted that all three instances listed above were issues that the licensee failed to enter into the CAP until questioned by the inspectors. Consequently, the inspectors were concerned with the threshold for entering conditions adverse to quality into the CAP. The licensee generated AR 01436424, 2014 PI&R Untimely CAP creation, to address the potential programmatic issue. For corrective actions to address this issue, the licensee was planning to perform an RCE to determine the necessary actions to ensure identified conditions adverse to quality are entered into the CAP to ensure issues are promptly evaluated and corrected as appropriate.

Analysis:

The inspectors determined that the failure to properly implement FP-PA-ARP-01, which requires that identified conditions adverse to quality be entered into the CAP in a timely and effective manner, was a performance deficiency. The inspectors determined that the performance deficiency was more than minor because if left uncorrected, the performance deficiency would have the potential to lead to a more significant safety concern. Specifically, failing to implement CAP procedures could result in subsequent failure to address and resolve more significant conditions adverse to quality. Because all three instances discussed above qualitatively impacted the containment system, the finding is associated with the Barrier Integrity cornerstone.

The inspectors utilized IMC 0609, Significance Determination Process, 0609.04, Initial Characterization of Findings, and concluded that this findings significance was best characterized by using IMC 0609, Appendix M, Significance Determination Process Using Qualitative Criteria. Based upon the fact that the three instances discussed above did not rise to a level of greater than very low safety significance, the inspectors determined that this issue was best characterized as having very low safety significance (Green). The inspectors concluded that this finding was associated with an Identification cross-cutting aspect in the PI&R cross-cutting area.

Specifically, workers did not implement the CAP at an appropriate threshold for identifying issues to ensure that conditions adverse to quality were addressed in a timely manner. [P.1]

Enforcement:

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

Contrary to the above, prior to May 19, 2014, the licensee failed on three occasions to accomplish procedure FP-PA-ARP-01, CAP Action Request Process, Revision 37.

Specifically, Step 5.3.1 of FP-PA-ARP-01 stated, in part that The Corrective Action Program Action Request Process SHALL be used to document and track all problems, issues and concerns, including all conditions adverse to quality. Each instance required NRC inspector questioning of potential degraded or non-conforming conditions affecting plant equipment prior to CAP ARs being generated to evaluate the conditions. Because this violation was of very low safety significance and was entered into the licensees CAP as ARs 01436424 and 01431729, this violation is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy.

(NCV 05000282/2014007-01; 05000306/2014007-01, Failure to Implement the CAP Action Request Process Procedure)

Inadequate Procedure for Identification of Significant Conditions Adverse to Quality

Introduction:

The inspectors identified a Green finding and NCV of Title 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures and Drawings, for the licensees failure to prescribe a procedure appropriate to the circumstances with respect to the identification of a SCAQ. Specifically, FP-PA-ARP-01, CAP Action Request Process, provided an overly restrictive definition of what constituted a SCAQ. Consequently, the licensee staff did not identify a failed Residual Heat Removal (RHR) pump shaft as a SCAQ.

Description:

On June 26, 2014, the inspectors identified that licensee procedure FP-PA-ARP-01, CAP Action Request Process, provided an overly restrictive definition of SCAQ as compared to the definition identified in ASME NQA-1, Quality Assurance Requirements for Nuclear Facility Applications. Subsequently, the inspectors identified an example where the licensee staff failed to identify an April 22, 2012, RHR pump shaft failure as a SCAQ. The inspectors were concerned that failure to provide a procedure, appropriate to the circumstances with respect to identification of a SCAQ could result in the failure to implement corrective actions that preclude repetitive failures of safety-related components.

In the licensees QATR, Section B.13 Corrective Action, the licensee committed to compliance with the 1994 Edition of NQA-1, Quality Assurance Requirements for Nuclear Facility Applications, in establishing provisions for corrective actions and control of non-conforming items. In NQA-1, a SCAQ was defined as one which, if uncorrected, could have a serious effect on safety or operability. However, in Step 4.33 of FP-PA-ARP-01, the licensee defined a SCAQ as a condition adverse to quality that represents a significant potential or actual threat to the radiological safety of plant workers (radiation protection) or the public (nuclear safety). The inspectors noted that the FP-PA-ARP-01 SCAQ definition added key words such as significant potential and actual threat and dropped the key words if uncorrected, serious, and operability. With these changes, the inspectors concluded that the licensee had created an overly restrictive definition of what constituted a SCAQ at the station.

The inspectors performed a sampling review of past equipment failures of safety-related equipment and identified an example where the licensee had failed to identify the equipment failure as a SCAQ. On April 22, 2012, the 21 RHR pump experienced a total loss of developed head caused by a pump shaft that cracked and failed with Unit 2 in Mode 6 and the RHR system providing shutdown cooling for the core. This issue was identified as a condition adverse to quality and entered into the CAP (e.g., severity level B ARs 01334924 and 01334933 - 21 RHR Pump Shaft Failure). However, the cracked pump shaft, if uncorrected would have a serious effect on system operability and the safe operation of the plant because at the time of failure, the RHR system was relied on to remove core decay heat and the 21 RHR pump shaft failure disabled the A train of RHR. Therefore, the inspectors determined that this issue met the NQA-1 definition of a SCAQ that the licensee had not identified as such.

In May of 2012, the licensee completed an extent of condition review (AR 01334924) for the 21 RHR pump shaft failure and documented this review in engineering change (EC)20015, Immediate Action Extent of Condition Review for 21 RHR Pump Failure. The scope of the licensees review included the operating, testing, and maintenance history for each RHR pump. Based upon this review, the licensee concluded that the other RHR pumps showed no signs of pump degradation similar to the failed 21 RHR pump.

Specifically, for the 21 RHR pump, a step change in vibration was recorded during full flow tests and a step change (decrease) in total developed head occurred after pump bushing and motor bearing replacement in November of 2006. These conditions were not evident on any of the other RHR pumps; therefore the licensee concluded that no immediate extent of condition concern existed for the other RHR pumps.

In July of 2012, the licensee completed an equipment cause evaluation (AR 01334924)that documented the investigation into the cause of the 21 RHR pump shaft failure which experienced a complete severance of the shaft underneath the shaft sleeve in the stuffing box region, corresponding to the location of an O-ring groove. The licensee concluded Clear evidence exists that the 21 RHR pump was subject to gross misalignment for a period of time between the motor bearing and pump bushing work that occurred in

2R24 and the Chesterton seal installation done in 2R25. There is no evidence that

any of the other pumps were subjected to a similar stressor. However, it is reasonable to believe that all the other pump shafts may have similar degrees of cold work in the material exposed to the pumped fluid, since they were all purchased on the same order. Similarly, it is reasonable that similarly aggressive chemical environments may exist in the crevice under the shaft sleeve and O-ring of the other pumps and that there may be sulfate contamination from a historical ion exchange resin intrusion event. Therefore, the necessary conditions for stress corrosion cracking exist for all the pumps, and such cracking, in conjunction with the natural stress riser created by the O-ring groove, may possibly result in fatigue crack propagation even in the absence of the increased stress magnitude that affected the 21 RHR pump as a result of the misalignment. Therefore, it is prudent to inspect the other pump shafts for incipient cracking using dye penetrant or other suitable surface examination method over the course of the next several refueling outages. Work orders have been initiated to perform the inspections as noted in the corrective actions section.

The licensee had deferred a planned inspection of the B train RHR pump shafts during the 2013 Unit 2 refueling outage and at of the conclusion of this inspection, had not performed inspections for any of the other RHR pump shafts. Therefore, the inspectors could not determine if the licensees RHR pump shaft inspection schedule would be sufficiently timely to preclude recurrence of another RHR pump shaft failure.

In response to this finding, the licensee entered this concern into the CAP as AR 01436342, and initiated actions to establish compensatory measures for screening ARs until this issue was corrected.

Analysis:

The inspectors determined that the licensees failure to prescribe a procedure appropriate to the circumstances with respect to identification of a SCAQ was a performance deficiency. The performance deficiency was determined to be more than minor in accordance with IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue Screening, because, if left uncorrected the performance deficiency would have the potential to lead to a more significant safety concern. Specifically, the failure to provide an adequate definition of a SCAQ did result in a failure to identify a SCAQ and could result in a failure to implement corrective actions that preclude repetitive failures of safety-related equipment. Although, this issue could potentially affect each of the Reactor Safety Cornerstones, the inspectors elected to evaluate this issue under the Mitigating Systems Cornerstone because of the actual SCAQ example identified associated with the failed 21 RHR pump shaft.

The inspectors completed a Phase 1 significance determination of this issue using IMC 0609, Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings, and IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power. The inspectors answered No to each of the questions in Exhibit 2, Section A, Mitigating Systems Screening Questions, therefore the finding screened as very low safety significance (Green). Specifically, the inspectors did not identify an example where the failure to provide a procedure appropriate to the circumstances with respect to identification of a SCAQ had resulted in repetitive failures of safety-related equipment.

The finding was determined to have a cross-cutting aspect in the area of problem identification and resolution, self-assessment component, because the licensee failed to perform sufficiently self-critical assessments of the CAP process. Specifically, the failure to identify the overly restrictive definition of a SCAQ during previous audits of the CAP was caused by an insufficiently self-critical audit focus. [P.6]

Enforcement:

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

Contrary to this requirement, prior to June 26, 2014, the licensee had not prescribed a procedure appropriate to the circumstances for identification of a SCAQ. Specifically, the procedure FP-PA-ARP-01, CAP Action Request Process, definition of a SCAQ was not appropriate for the circumstances. Because this violation is of very low safety significance and was entered into the corrective action program as AR 01436342, this violation is being treated as a non-cited violation consistent with Section 2.3.2 of the NRC Enforcement Policy.

(NCV 05000282/2014007-02; NCV 05000306/2014007-02, Inadequate Procedure for Identification of Significant Conditions Adverse to Quality)

(2) Effectiveness of Prioritization and Evaluation of Issues Based on the results of the inspection, the inspectors concluded that, overall, the licensee was effective in prioritizing and evaluating issues commensurate with the safety significance of the identified issue, including an appropriate consideration of risk. The inspectors determined, in general, that issues were being appropriately screened and issues identified of higher significance were assigned root or apparent cause evaluations. Notably, the inspectors concluded that the licensees prioritization and evaluation of issues had shown signs of improvement since the 2012 biennial PI&R inspection considering the documented observational concerns in this area. In particular, the team noted improvements in RCE documentation with respect to clarity of the causes, contributors, and line of sight to the corrective actions and effectiveness reviews. The station credited behavior changes that led to these improvements and an ongoing effort to modify CAP procedures. Since this effort was still underway, the team could not comment on the efficacy of planned changes.

The team did identify some examples that were not captured through procedure or process changes. For example:

• the permitted use of sub-assignments for corrective actions to prevent recurrence (CAPRs) made it difficult to verify that the sub-assignments truly captured the parent CAPR assignment;

• in several cases it was difficult to determine how effectiveness review (EFR)assignments captured multiple CAPR assignments (examples of RCEs with multiple CAPRs but only one or two EFRs). The licensee captured this observation in AR 01434274;

• the team recognized a requirement within FP-PA-ARP-01 that All assignments SHALL be written to the SMARTS (specific, measurable, accountable, reasonable, timely, and sustainable) criteria, however, many of the CAP sub-procedures allowed adherence to the SMARTS model as optional. Based on the level of documentation for many assignments, it was practically impossible to verify how each assignment followed or even considered the SMARTS model in developing assignments.

Without an accountability mechanism for this requirement, or guidance as to when the SMARTS model is truly required for particular assignments, the station was vulnerable to not meeting the requirements/expectations. The licensee captured this observation in AR 01434473; and

• the team noted instances where the RCE document template/form guidance did not, in all cases, align with CAP procedure requirements. The licensee captured this observation in AR 01434638.

Overall, it remained difficult to identify where perceived behavioral improvements were reflected in procedure changes to ensure sustainability of the behaviors.

Based on the ongoing efforts by the station regarding the aforementioned CAP deep dive assessment and resulting actions, the team could not make an assessment on whether these efforts would be successful and sustainable. Most significantly, RCE 01349769, Ineffective Corrective Action Program Implementation, Revision 0 was performed and completed in December 2012 following the results of the August 2012 biennial PI&R inspection. This RCE was subsequently revised in April 2013, and all CAPRs were considered completed by July 2013. In February and March of 2014, in preparation for the 2014 biennial PI&R inspection, the licensee performed an inspection readiness self-assessment (SAR) under SAR 01407344. The SAR identified several areas for improvement related to prior actions to address CAP implementation issues, but not all review objectives were performed due to resource issues. In April 2014, the Prairie Island nuclear oversight (NOS) department performed Observation Report2014-01-040 to review the SAR results. This NOS report highlighted the improper readiness for the 2014 biennial PI&R inspection based on the ineffectiveness of prior corrective actions to address CAP implementation issues. The report generated a NOS Escalation Level 1 findingrequiring station management response. Among other actions planned, the decision was made to re-open and once again revise RCE 01349769 in May 2014.

Due to the significance of the RCE 01349769 revision and large number of actions remaining in-progress during this 2014 biennial PI&R inspection, the inspectors could not review the adequacy, sustainability, or effectiveness of any planned actions in order to provide a current overall assessment of Prairie Islands CAP.

There were no items identified in the operations, engineering, or maintenance backlogs that were risk-significant, individually or collectively. The inspection team did not identify any significant issues during the review of the operational decision making (ODMI)process.

Findings Failure to Evaluate Past Operability and Reportability of the Cooling Water System

Introduction:

The inspectors identified a Green finding and NCV of Title 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures and Drawings, for the licensees failure to accomplish FP-PA-ARP-01, CAP Action Request Process, to notify the shift manager of an operability/reportability concern and initiate an AR for past periods of plant operation with a cooling water (CL) system strainer isolated. Specifically, with a CL header strainer isolated, a seismic event could lead to operation of the remaining CL strainer with excessive flow (e.g., outside analyzed limits) and adversely affect safety-related components cooled by the CL system.

Description:

In September 2013, the NRC identified a finding for the licensees failure to review the suitability of the CL strainers under post-seismic flow conditions. Specifically, the post-seismic system flow rate could exceed the design maximum flow rate of the CL system strainer if one CL header strainer was out for maintenance. Subsequently, the licensee failed to notify the shift manager and perform an operability/reportability assessment for periods of past plant operation with CL strainers isolated. The inspectors were concerned that failure to investigate and evaluate periods of past plant operation with isolated CL strainers may have resulted in operation of the plant in an unanalyzed condition. Specifically, operation of the CL system at flow rates above the design maximum for the strainer could result in a strainer failure that would release debris and adversely affect cooling of the downstream safety-related components.

On April 19, 2013, the NRC identified a finding of very low safety significance and associated NCV of 10 CFR Part 50, Appendix B, Criterion III, Design Control, for the licensees failure to review the suitability of the CL strainers under post-seismic flow conditions. Specifically, post-seismic hydraulic parameters were greater than the vendor design values for the strainers. The NRC documented this finding as NCV 05000282/2013007-02; 05000306/2013007-02, Failure to Review the Suitability of the CL Strainers under Post-Seismic Flow Conditions, and the issue was recorded in the licensees CAP as AR 01378695. The licensees immediate action was to initiate a standing order for operations to be aware that the operability of a CL header would be questionable with one strainer isolated. In addition, a historical review determined the total duration of one strainer isolation for the last year was 337.25 hours2.893519e-4 days <br />0.00694 hours <br />4.133598e-5 weeks <br />9.5125e-6 months <br />. This duration was used by the SRA in determining the significance of this finding. The licensees corrective actions at the time of this inspection were to evaluate the condition and initiate further actions as necessary.

On June 25, 2014, the inspectors identified that the licensee corrective actions for NRC finding NCV 05000282/2013007-02; 05000306/2013007-02 did not include a review of past operating configurations to evaluate operability and reportability. The licensee implemented changes to the site operating instructions to require entry into the TS 3.7.8 LCO if a strainer was removed from service and proposed design changes that included replacement of the affected strainers. However, the licensee did not notify the shift manager or initiate a new CAP AR to investigate or evaluate past periods of operability with CL strainers isolated which was not in accordance with the required actions in procedure FP-PA-ARP-01 CAP Action Request Process.

In response to this finding, the licensee entered this issue into the CAP as AR 01436231 and initiated actions to evaluate past periods of operation with isolated CL strainers.

Analysis:

The inspectors determined that the licensees failure to accomplish procedure FP-PA-ARP-01, CAP Action Request Process, to notify the shift manager for operability/reportability concerns and initiate a CAP for past plant operation with the CL system strainer isolated was a performance deficiency. This performance deficiency was determined to be more than minor in accordance with IMC 0612, "Power Reactor Inspection Reports," Appendix B, "Issue Screening," because, if left uncorrected the performance deficiency would have the potential to become a more significant safety concern. Specifically, the failure to accomplish procedure FP-PA-ARP-01 potentially resulted in a failure to notify the NRC of an unanalyzed operating condition which would impede or impact the regulatory process. Additionally, the performance deficiency was also determined to be more than minor because it was associated with the Mitigating Systems Cornerstone attribute of design control and adversely affected the Cornerstone objective of ensuring the availability, reliability, and capability of mitigating systems to respond to initiating events. Specifically, flow rates higher than design values may cause failure of the strainer that would release debris and adversely affect cooling of the downstream safety-related components.

The inspectors completed a Phase 1 significance determination of this issue using IMC 0609, Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings, and IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power. The inspectors answered Yes to Question 2 of Section A of Exhibit 2, Mitigating Systems Screening Questions.

Specifically, the CL system may not have been able to perform its design cooling functions during past periods of operation with one CL header strainer isolated.

Therefore, the finding required a detailed risk evaluation which had been previously completed by an SRA for the original finding (NCV 05000282/2013007-02; 05000306/2013007-02). Specifically, the SRA had previously determined that the bounding core damage frequency for this issue was 1.9E-7/yr. and concluded the total risk increase to the plant due to this finding was of very low risk significance (Green).

The finding was determined to have a cross-cutting aspect in the area of human performance, consistent process, because the licensee failed to use a consistent, systematic approach to make decisions. Specifically, the licensee failed to use the CAP process in evaluation of the past operability and reportability of the CL system with the CL system strainers isolated. [H.13]

Enforcement:

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

Contrary to the above, from October 23, 2013, through June 25, 2014, (reference AR 01378695), the licensee failed to accomplish procedure FP-PA-ARP-01, CAP Action Request Process, Revision 37, Step 5.9.1 which stated, in part, IF new operability/reportability/functionality concerns are identified, THEN notify the shift manager immediately, and, IF a new problem or condition adverse to quality is identified, THEN initiate a CAP. Specifically, when the licensee identified/confirmed a CL system operating configuration that was a new operability, reportability or functionality concern, this new condition adverse to quality was not captured within a CAP AR to notify the shift manager a past operability (reportability) concern. Because this violation is of very low safety significance and was entered into the corrective action program as AR 01436231, this violation is being treated as a NCV consistent with Section 2.3.2 of the NRC Enforcement Policy.

(NCV 05000282/2014007-03; NCV 05000306/2014007-03, Failure to Evaluate Past Operability and Reportability of the Cooling Water System)

Failure to Update the Updated Final Safety Analysis ReportPressure Isolation Valves

Introduction:

The inspectors identified a Severity Level IV NCV of Title 10 CFR 50.71(e),

Periodic Update of the Final Safety Analysis Report, and an associated Green finding for the licensees failure to update the Updated Final Safety Analysis Report (UFSAR)with a complete list of pressure isolation valves (PIVs) and periodic acceptance test requirements that had been reported to the Commission. Specifically, the licensee did not update Prairie Island Updated Safety Analysis (USAR), Section 4.6.1.2.1, Pressure Isolation Valves, to include all PIVs and their associated test requirements.

Discussion: In June 1987, the licensee submitted a list of valves to the NRC in response to Generic Letter (GL) 87-06, Periodic Verification of Leak Tight Integrity of PIVs, and identified the test methods used to confirm the leak tight integrity of these PIVs. The licensee did not incorporate this information into the USAR. The licensee subsequently identified a group of the PIVs reported to the NRC in their response to GL 87-06 which had not been periodically tested, and identified a contributing cause for this error as a failure to adequately update the In-service Test (IST) Program basis documents.

However, the licensees corrective actions to resolve this issue did not include updating the USAR with a complete list of PIVs. The inspectors were concerned that failure to update the USAR with a complete list of PIVs and their associated test requirements could again result in a failure to complete periodic PIV leak testing.

In March 1987, the NRC issued GL 87-06 to verify the test methods that confirmed the leak-tight integrity of PIVs. PIVs were defined by the NRC as any two valves in series within the reactor coolant pressure boundary that separated the high pressure reactor coolant system from attached low pressure systems. Further, the NRC identified that periodic testing of PIVs was necessary to assure the integrity of the reactor coolant pressure boundary. In June 1987, the licensee responded to GL 87-06 and identified a list of PIVs including the type of acceptance tests applied for each PIV. However, the licensee did not update the USAR to reflect this information. In June 1993 and May 1996, the licensee changed the testing category of 14 PIVs in the IST Program that resulted in deletion of the periodic leak acceptance tests for these PIVs. In September 1997, the licensee issued a USAR change to revise their original GL 87-06 commitment and reduce the number of PIVs to those identified in the TS (reference basis section for TS 3.4.15). Subsequently, the licensee determined that the decision to remove these PIVs from the IST Program was not correct and in November 2013, issued EC-23049, Acceptance of True Norths Pressure Isolation Valve Evaluation for Prairie Island, to record the complete scope of PIVs with leakage acceptance testing. However, the licensee failed to notify the Commission of this commitment change and to update the USAR to reflect this information.

In April 2013, the licensee completed RCE 01365473, Failure to Test Category A PIVs per the American Society of Mechanical Engineers Operation and Maintenance Code and GL 87-06. The licensee identified several PIVs that had not been properly tested and the licensees RCE team concluded the root cause was a failure of site engineering management to recognize the importance of industry participation to ensure awareness, currency, and alignment to industry standards for regulatory required Engineering Programs. The licensees RCE team also identified four contributing causes for this error that included the site IST Program not having an adequately documented basis that met current industry standards for individual component categorization, scope, and regulatory requirements. However, this conclusion did not prompt a corrective action to correct the incomplete list of PIVs and associated test requirements identified in USAR section 4.6.1.2.1 Pressure Isolation Valves. Based upon review of the licensees timeline of decisions and inappropriate actions identified in RCE 01365473, the inspectors concluded that failure to update the USAR with the complete list of PIVs was a potential contributor to the licensees failure to properly test these valves. As of June 25, 2014, the licensee had not updated the USAR to reflect the complete list of PIVs identified in their current IST Program and EC-23049.

In response to this finding, the licensee entered this issue into the CAP as AR 01436039 and initiated actions to change the USAR to incorporate the complete list of PIVs as identified in EC-23049.

Analysis:

The inspectors determined that the failure to update the USAR with a complete list of PIVs was contrary to 10 CFR 50.71(e) and was a performance deficiency that warranted a significance evaluation. This performance deficiency was determined to be more than minor in accordance with IMC 0612, "Power Reactor Inspection Reports," Appendix B, "Issue Screening," because, if left uncorrected, the performance deficiency would have the potential to lead to a more significant safety concern. Specifically, failing to update the USAR with the complete list of PIVs and their associated test requirements could result in a failure to periodically test these valves. A lack of periodic PIV testing could result in leaving degraded PIVs in service which would increase the probability of an intersystem loss-of-coolant accident (LOCA) that bypasses the containment. Additionally, the failure to include PIVs in the USAR was more than minor because it was associated with the Initiating Event Cornerstone attribute of Equipment Performance and adversely affected the Cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions.

Violations of 10 CFR 50.71(e) are dispositioned using the traditional enforcement process because they are considered to be violations that potentially impede or impact the regulatory process. This violation was also associated with a finding that has been evaluated by the SDP and communicated with a SDP color reflective of the safety impact of the deficient licensee performance. The SDP, however, does not specifically consider regulatory process impact. Thus, although related to a common regulatory concern, it is necessary to address the violation and finding using different processes to correctly reflect both the regulatory importance of the violation and the safety significance of the associated finding.

The inspectors completed a Phase 1 significance determination of this issue using IMC 0609, Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings, and IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power. The inspectors answered No to the LOCA Initiators questions in Exhibit 1, Section A, Initiating Events Screening Questions, therefore the finding screened as very low safety significance (Green).

Specifically, the inspectors concluded that the failure to update the USAR with the complete list of PIVs had not yet resulted in operation of the plant with unacceptable PIVs and thus had not increased the probability of an intersystem LOCA. The inspectors determined this finding to have a cross-cutting aspect in the area of human performance, documentation component, because the licensee failed to maintain complete, accurate, and up-to-date documentation of the PIVs in the USAR. [H.7]

In accordance with Section 6.1.d.3 of the NRC Enforcement Policy, this violation was also categorized as Severity Level IV because the licensees failure to update the USAR as required by 10 CFR 50.71(e) had not yet resulted in any unacceptable change to the facility or procedures.

Enforcement:

Title 10 CFR 50.71(e) requires in part, that licensees shall periodically update the UFSAR, originally submitted as part of the application for the operating license, to assure that the information included in the report contains the latest information developed. This submittal shall include the effects of all the changes necessary to reflect information and analysis submitted to the Commission by the licensee or prepared by the licensee pursuant to Commission requirement since the submittal of the original USAR, or as appropriate, the last update to the USAR under this section [USAR].

Contrary to the above, from 1987 until September 30, 1997, and from November of 2013, through June 25, 2014, the licensee did not update the USAR to reflect information submitted to the Commission. Specifically, the licensee failed to update the USAR with the complete list of PIVs including the applicable acceptance test requirements. In accordance with the Enforcement Policy, Section 6.1.d.3 the violation was classified as a Severity Level IV violation. Because this violation was of a very low safety significance, was not repetitive or willful, and was entered into the licensees CAP as AR 01436039, this violation is being treated as a Severity Level IV NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy.

(NCV 05000282/2014007-04; 05000306/2014007-04, Failure to Update the UFSAR for Pressure Isolation Valves)

(3) Effectiveness of Corrective Action Based on the results of the inspection, the inspectors concluded that the majority of corrective actions reviewed were generally appropriate for the identified issues, with some examples to the contrary. The team acknowledged recent NOS observations related to the CAP, in particular the inappropriate closure or ineffectiveness of CAPRs to address long-standing CAP issues. The team also noted several examples where corrective actions addressing selected NRC documented violations were not timely and were potentially narrowly focused due to the lack of extent of condition reviews. The inspectors review going back 5 years of the stations efforts to address issues with the EDG and safety-related switchgear systems did not identify any new concerns, but considering the approximately six NRC-identified findings related to these systems over the last 2 years, the team was concerned with the timeliness of corrective actions and the number of challenges in addressing long term issues.

The team noted several root cause evaluations that determined deficiencies in site-wide behaviors as the root cause(s). In order to generate CAPRs, there were several examples where the actions involved coaching/counseling, providing training, etc.

These types of CAPRs proved not only very difficult to achieve, but also very difficult to verify effectiveness and sustainability. The inspectors were concerned that some actions taken to address long-standing issues were attributed, in part, to one-time actions to address behavioral issuesresulting in many RCEs having to be revised at later dates. Additionally, the inspectors noted several examples where contributing causes pointed to straightforward procedure or process changes that, had the procedure/process been adequate in the first place, could have prevented the issue altogether. Overall, there were several examples where corrective actions were made more complicated than they needed to beresulting in confusion by plant staff as to what exactly needed to be addressed. There was a sense by the inspection team that root cause tools used could be driving corrective actions that were difficult to achieve versus the station first addressing what could be done to prevent recurrence through permanent procedure/process changes. These changes, in the end, could have proved themselves to be more measureable, sustainable, and likely more effective in the long term.

The inspectors acknowledged that Prairie Islands corrective action program processes were very sophisticated. However, the team found some processes convoluted, resource intensive, and confusing to use. Because of this, the team noted that several potential areas for error traps existed. For example, the team found instances where multiple cross-references and closures to processes outside the CAP led to assignments being inappropriately cancelled, lost, or difficult to locate (see finding discussed below);confusion related to irregular coding for assignments that lead to questions of what the assignments were truly addressing, and frustration in simply trying to determine how actions were ultimately resolved. Some of these observations were also evident in retrieving some responses by the stations inspection support team during the inspection (refer to AR 01435531).

The team noted an abnormally high number of B level corrective actions going back as far as 2006 that have still not been closed. Although station CAP backlogs remained high, the licensee was making progress with burn-down curves moving in right direction.

The inspectors reviewed RCE 01378655, Root Cause Analysis Recommended for P.1.c CAPs, completed in May of 2013 to review an emerging cross-cutting theme in the area of PI&R. The RCE identified one root cause and determined that due to the root cause being similar to a root cause identified in RCE 01349769, Ineffective CAP Implementation; the licensee took some credit for a CAPR within that evaluation.

However, the inspectors identified that two new additional corrective actions (CA 01378655-03 and-15) were also generated to address the root cause for RCE 01378655. The inspectors questioned why these corrective actions were not labeled as CAPRs in accordance with station procedures. The licensee acknowledged these errors and documented the issue in CAP 01435079. The inspectors considered the failure to properly document CAPRs for a new SCAQ as an NRC-identified performance deficiency for failing to follow procedure FP-PA-RCE-01, Root Cause Evaluation Manual. Specifically, Step 5.4.11 required, in part, that CAPRs to address the Root Cause SHALL be developed. The inspectors determined that the performance deficiency was of minor significance because the two corrective actions were completed appropriately, and had EFRs assigned and completed successfullyeven though the CAs were not categorized as CAPRs (i.e., if left uncorrected, would not have led to a more significant safety concern). The licensee was in the process of revising the categorization of CA 01378655-03 and-15 within the CAP, and reviewing the basis for the assignment error in RCE 01378655.

Findings Failure to Follow Procedures for Cancelling Non-CAP Action Assignments

Introduction:

The inspectors identified a Green finding and NCV of Title 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures and Drawings, for the licensees failure to accomplish Attachment 14, CAP to External Process Interface, of procedure FP-PA-ARP-01, CAP Action Request Process. Specifically, the inspectors identified several examples where severity level C CAP AR actions were closed to processes outside the CAP, and then subsequently cancelled without appropriate justification or documentation.

Description:

In April 2013, NRC inspectors identified during a triennial component design basis inspection (CDBI), two examples where severity level C ARs were closed to procedure change requests (PCRs), but were then subsequently cancelled without justification. The inspectors determined that both issues, on their own merit, represented minor performance deficiencies. The licensee documented the collective CDBI concerns within AR 01378248 and changed station procedures to help ensure that C level ARs closed to PCRs would not be inappropriately or unjustifiably canceled.

In preparation for the 2014 biennial PI&R inspection, the team received the information related to the CDBI issue discussed above for follow-up review due to the potential for extent of condition. The 2014 biennial PI&R inspectors requested a search for severity level C condition adverse to quality ARs of top ten risk significant systems, from November 2013 through June 2014 that were closed to non-CAP processes (PCRs, work requests, work orders, engineering changes and requests, etc.), and then subsequently cancelled. After compiling and reviewing the list, three notable examples of severity level C ARs documenting conditions adverse to quality and fire protection were identified:

• CAP AR 01394131, B&W AFCR N8-003 As-Found Conditions on New RSG 21, associated with the as-found inspection of replacement steam generator 21 channel head area on the hot leg side containing a small visible indication during a non-destructive examination. The AR was closed to a work request, but then subsequently cancelled without documentation of resolution. This indication was not part of the reactor coolant system pressure boundary. After further investigation, the issue was forwarded to the stations vendor that determined no additional action was required; however, the cancellation of the WR was not documented. The licensee documented this issue in ARs 01435428 and 01435438 to determine why the work request was cancelled and to document the final disposition;

• CAP AR 01164738, FP System Walkdown Findings, associated with a station engineers fire protection system walk down that identified, in part, the need to replace supply tubing for a fire protection system component. A work request and work order were both cancelled inappropriately (tubing was replaced, but work completion was not documented and different tubing materials were used).

The licensee documented this issue in AR 01435954 to further investigate how the work was performed under a cancelled work order and also whether the change in tubing material resulted in an unevaluated modification to the system; and

• CAP AR 01427928, D6 ENG 1 L/O PS 2PS-6185 Was Not Repeatable During Calibration, associated with a lubricating oil system pressure switch calibration that was not repeatable as expected during a maintenance activity. Although the licensee determined that the non-repeatable pressure switch issue did not prevent declaring the D6 emergency diesel generator operable following the maintenance, the work request assigned to either replace or review the concern by engineering was inappropriately cancelled without any justification. The licensee documented this issue in AR 01435962 to further investigate the work request cancellation.

The inspectors were concerned that aside from prior corrective actions to address shortcomings in PCR cancellation from the 2013 CDBI issues, a more than minor programmatic issue existed with respect to non-CAP assignment cancellations.

Specifically, the inspectors were concerned that sufficient automated CAP process barriers were not in place to ensure that Attachment 14, CAP to External Process Interface, of procedure FP-PA-ARP-01, CAP Action Request Process, was consistently followed and complied with. Attachment 14 General Guidance stated, in part, that IF any action in an outside process terminates in a status that did not achieve the requested result (i.e., CANCELLED), THEN the CAP Owed-To must develop a suitable alternative solution and initiate actions to address the condition or cause OR provide adequate basis for non-performance of the action. For PCRs and some other non-CAP assignments, the Prairie Island automated CAP process contained built-in software flags to ensure that proper cancellation actions were taken and documented.

For other non-CAP assignments such as work orders and work requests, manual reviews by station personnel were required to ensure the FP-PA-ARP-01, Attachment 14 requirements were met. There was no such manual review process in place at the time of this inspection and the identification of inappropriate cancellations were left to CAP screening members or other individual contributors.

In response to the inspectors concern, the licensee entered this issue into the CAP as CAP 01436258 and initiated actions to develop more automated barriers within the CAP processes.

Analysis:

The inspectors determined that the licensees failure to accomplish 14 of procedure FP-PA-ARP-01, CAP Action Request Process, Revision 37 to develop a suitable alternative solution and initiate actions to address the condition or cause or provide adequate basis for non-performance of the action was a performance deficiency. This performance deficiency was determined to be more than minor in accordance with IMC 0612, "Power Reactor Inspection Reports," Appendix B, "Issue Screening," because, if left uncorrected it would have the potential to lead to a more significant safety concern. Specifically, the failure to ensure that severity level C conditions or causes of conditions adverse to quality were appropriately addressed, or non-performance of actions appropriately justified, had the potential to lead to a more significant safety concern.

The inspectors utilized IMC 0609, Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings, and concluded that this findings significance was best characterized by using IMC 0609, Appendix M, Significance Determination Process Using Qualitative Criteria. Based upon the fact that the three instances discussed above did not rise to a level of greater than very low safety significance, the inspectors determined that this issue was best characterized as having very low safety significance (Green). The inspectors determined that the performance characteristic of the finding that was the most significant causal factor of the performance deficiency was associated with the cross-cutting aspect of Problem Identification and Resolution, and involving the organization taking effective corrective actions to address issues in a timely manner commensurate with their safety significance. Specifically, following the realization in April 2013 of potential flaws in the CAP processes to allow inappropriate cancellations of severity level C CAP ARs after being closed to the non-CAP PCR assignments, the station failed to correct the vulnerabilities that existed for other non-CAP assignments. [P.3]

Enforcement:

Title 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures and Drawings, requires in part, that activities affecting quality shall be accomplished in accordance with written procedures.

Procedure FP-PA-ARP-01, CAP Action Request Process, Revision 37, Attachment 14, CAP to External Process Interface, General Guidance, states, in part, IF any action in an outside process terminates in a status that did not achieve the requested result (i.e., CANCELLED), THEN the CAP Owed-To must develop a suitable alternative solution and initiate actions to address the condition or cause OR provide adequate basis for non-performance of the action.

Contrary to the above, on June 25, 2014, the inspectors identified three examples of severity level C CAP ARs that had been closed to an outside process, but then subsequently cancelled without developing an alternative solution, initiating actions to address the conditions or causes, or providing adequate basis for non-performance of the action. Because this violation is of very low safety significance and was entered into the CAP as AR 01436258, this violation is being treated as a NCV consistent with Section 2.3.2 of the NRC Enforcement Policy.

(NCV 05000282/2014007-05; NCV 05000306/2014007-05, Failure to Follow Procedures for Cancelling Non-CAP Action Assignments)

.2 Assessment of the Use of Operating Experience

a. Inspection Scope

The inspectors reviewed the licensees implementation of the facilitys operating experience (OE) program. Specifically, the inspectors reviewed implementing OE program procedures, observed daily meetings for the use of OE information, and reviewed completed evaluations of OE issues and events. The intent was to determine if 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 implemented effectively and in a timely manner.

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

b. Findings

No findings were identified.

.3 Assessment of Self-Assessments and Audits

a. Inspection Scope

The inspectors reviewed selected self-assessments and NOS observation reports. The inspectors evaluated whether these self-assessments and observations 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 self-assessment and NOS observation programs.

Assessment Based on the results of the inspection, the inspectors concluded that self-assessments and NOS observations were typically accurate, thorough, and effective at identifying issues and enhancement opportunities at an appropriate threshold level. The self-assessments and observations were completed by personnel knowledgeable in the subject area. In many cases, these self-assessments and observations had identified numerous issues that were not previously recognized by the licensee. These issues were entered into condition reports as required by CAP procedures.

With respect to the 2012 biennial PI&R inspection assessment in this area that considered NOS observations generally more intrusive, critical, of higher quality, and in-line with NRC inspection conclusions as compared to similar self-assessment reports, the 2014 biennial PI&R inspectors continued to agree with this assessment.

For example, as discussed above, the station performed an inspection readiness self-assessment for the 2014 biennial PI&R inspection; however, following an NOS observation of the self-assessment, many significant issues were noted as not being captured by the readiness self-assessment. The NOS observation also drove more significant and timely resolution of any areas that needed to be addressed with respect to the longstanding CAP implementation concerns. The inspectors also noted approximately six NOS Observation Reports associated with the Prairie Island CAP over the prior 2 years that, in many cases, identified several significant issues with the CAP that should have/could have been identified through self-assessments.

b. Findings

No findings were identified.

.4 Assessment of Safety-Conscious Work Environment

a. Inspection Scope

The inspectors interviewed selected Prairie Island personnel to determine if there were any indications that individuals were reluctant to raise safety concerns to their management, supervision, the Employee Concerns Program (ECP), or the NRC due to the fear of retaliation. The inspectors reviewed selected ECP activities to identify any emergent issues or potential trends. The inspectors also assessed the safety-conscious work environment (SCWE) through a review of ECP implementing procedures, discussions with the ECP representative, interviews with personnel from various departments, and reviews of ARs. The licensees programs to publicize the CAP and ECP were also reviewed. The inspectors reviewed licensee 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.

Assessment The inspectors did not identify any issues that suggested conditions were not conducive to the establishment and existence of a SCWE. Licensee personnel were aware of and generally familiar with the CAP and other processes, including the ECP, through which concerns could be raised. In addition, a review of the types of issues in the ECP database indicated that personnel were appropriately using the CAP and ECP to identify issues. The staff also indicated that management had been supportive of the CAP by providing time and resources for 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.

b. Findings

No findings were identified.

4OA6 Management Meetings

.1 Exit Meeting Summary

On June 27, 2014, the inspectors presented the inspection results to Mr. K. Davison, Site Vice President, 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. OConnor, Chief Nuclear Officer, Xcel Energy

K. Davison, Site Vice President

S. Sharp, Director of Site Operations

C. Younie, Plant Manager

C. Calia, Business Support Manager

T. Allen, Assistant Plant Manager

G. Johnson, Senior Manager, Site Engineering

J. Hallenbeck, Site Engineering Director

J. Ruttar, Operations Director

J. Anderson, Regulatory Affairs Manager

H. Butterworth, Nuclear Oversight Manager

J. Boesch, Maintenance Manager

B. Rogers, Performance Assessment Manager

J. Kivi, Employee Concerns Manager

J. Corwin, Security Manager

B. Boyer, Radiation Protection Manager

P. Oleson, Regulatory Affairs Analyst

M. Markley, Performance Assessment

A. Capristo, Nuclear Vice President, Licensing

A. Khanifar, Nuclear Vice President, Engineering

Nuclear Regulatory Commission

G. Shear, Director, Division of Reactor Safety

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

K. Stoedter, Senior Resident Inspector, Prairie Island Nuclear Generating Plant

LIST OF ITEMS

Opened/Closed

05000282/2014007-01; NCV Failure to Implement the CAP Action Request Process

05000306/2014007-01 Procedure (Section 4OA2.1b.(1))

05000282/2014007-02; NCV Inadequate Procedure for Identification of Significant

05000306/2014007-02 Conditions Adverse to Quality (Section 4OA2.1b.(1))

05000282/2014007-03; NCV Failure to Evaluate Past Operability and Reportability of

05000306/2014007-03 the Cooling Water System (Section 4OA2.1b.(2))

05000282/2014007-04; NCV Failure to Update the UFSAR for Pressure Isolation

05000306/2014007-04 Valves (Section 4OA2.1b.(2))

05000282/2014007-05; NCV Failure to Follow Procedures for Cancelling Non-CAP

05000306/2014007-05 Action Assignments (Section 4OA2.1b.(3))