IR 05000282/2016007

NRC Biennial Problem Identification and Resolution Inspection Report 05000282/2016007; 05000306/2016007, June 6, 2016 Through June 24, 2016

ML16204A226
Person / Time
Site:	Prairie Island
Issue date:	07/21/2016
From:	Kenneth Riemer NRC/RGN-III/DRP/B2
To:	Northard S Northern States Power Company, Minnesota
References
IR 2016007
Download: ML16204A226 (27)

Text

UNITED STATES uly 21, 2016

SUBJECT:

PRAIRIE ISLAND NUCLEAR GENERATING PLANT, UNITS 1 AND 2; NRC BIENNIAL PROBLEM IDENTIFICATION AND RESOLUTION INSPECTION REPORT 05000282/2016007; 05000306/2016007

Dear Mr. Northard:

On June 24, 2016, the U.S. Nuclear Regulatory Commission (NRC) completed a Problem Identification and Resolution biennial inspection at your Prairie Island Nuclear Generating Plant, Units 1 and 2. The enclosed inspection report documents the inspection results which were discussed on June 24, 2016, with you and other members of your staff.

This inspection was an examination of activities conducted under your license as they relate to problem identification and resolution and compliance with the Commissions rules and regulations and the conditions of your license. The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.

Based on the inspection samples, the inspection team concluded that implementation of the corrective action program (CAP) at Prairie Island Nuclear Generating Plant was effective. The inspectors noted that progress had been made in the implementation of the CAP since 2014.

Specifically, the inspectors noted improvement in the areas of problem identification, classification of issues in accordance with the CAP, and in the documentation of corrective actions. The inspectors also identified areas that needed improvement, based on observations and findings, specifically in the areas of evaluation, resolution, and prioritization of issues.

The station had a low threshold for identifying problems and entering them into the CAP. Items entered into the CAP were screened and prioritized in a timely manner using established criteria; in most cases were properly evaluated commensurate with their safety significance; and in most cases, corrective actions were implemented in a timely manner, commensurate with the safety significance. Operating experience was entered into the corrective action program and appropriately evaluated for applicability to station activities and equipment. The use of operating experience was integrated into daily activities. Audits and self-assessments were performed at appropriate frequencies and at an appropriate level to identify issues. The assessments reviewed were thorough and effective in identifying site performance deficiencies, programmatic concerns, and improvement opportunities. On the basis of interviews conducted during the inspection, workers at the site expressed freedom to enter safety concerns into the CAP. The inspectors did not identify any impediments to the establishment of a safety conscious work environment at the Prairie Island Nuclear Generating Plant.

Two NRC-identified findings of very low safety significance (Green) were identified and both findings involved a violation of NRC requirements. However, because of the very low safety significance, and because the issues were entered into your corrective action program, the NRC is treating these issues as a non-cited violations (NCV) in accordance with Section 2.3.2 of the NRC Enforcement Policy.

If you contest the subject or severity of these NCVs, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001, with a copy to the Regional Administrator, U.S. Nuclear Regulatory Commission - Region III, 2443 Warrenville Road, Suite 210, Lisle, IL 60532-4352; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the Resident Inspector Office at the Prairie Island Nuclear Generating Plant. In addition, if you disagree with the cross-cutting aspect assigned to the findings 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 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter and 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, Branch 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 05000282/2016007; 05000306/2016007

REGION III==

Docket Nos: 50-282, 50-306,72-010 License Nos: DPR-42, DPR-60, SNM-2506 Report No: 05000282/2016007; 05000306/2016007 Licensee: Northern States Power Company, Minnesota Facility: Prairie Island Nuclear Generating Plant, Units 1 and 2 Location: Welch, MN Dates: June 6 through June 24, 2016 Inspectors: R. Murray, Senior Resident Inspector (Team Lead)

M. Jones, Reactor Inspector P. LaFlamme, Resident Inspector J. Park, Reactor Inspector N. Shah, Project Engineer Approved by: K. Riemer, Chief Branch 2 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

Inspection Report 05000282/2016007, 05000306/2016007; 06/06/2016-06/24/2016;

Prairie Island Nuclear Generating Plant, Units 1 and 2; Problem Identification and Resolution.

This inspection was performed by a senior resident inspector, three NRC regional inspectors, and the resident inspector. Two Green findings were identified by the inspectors. Both findings were considered non-cited violations of NRC regulations. The significance of inspection findings is indicated by their color (i.e., greater than Green, or Green, White, Yellow, Red) and determined using Inspection Manual Chapter (IMC) 0609, "Significance Determination Process," dated April 29, 2015. Cross-cutting aspects are determined using IMC 0310, "Aspects within the Cross-Cutting Areas," dated December 4, 2014. All violations of NRC requirements are dispositioned in accordance with the NRCs Enforcement Policy, dated February 4, 2015. The NRC's 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 team concluded that implementation of the corrective action program (CAP) at Prairie Island Nuclear Generating Plant was effective. The licensee had a low threshold for identifying problems and entering them into the CAP. Items entered into the CAP were screened and prioritized in a timely manner using established criteria; were properly evaluated commensurate with their safety significance; and corrective actions were implemented in a timely manner, commensurate with the safety significance.

Operating experience was entered into the CAP and appropriately evaluated for applicability to station activities and equipment. The use of operating experience was integrated into daily activities. Audits and self-assessments were performed at appropriate frequencies and at an appropriate level to identify issues. The assessments reviewed were thorough and effective in identifying site performance deficiencies, programmatic concerns, and improvement opportunities. On the basis of interviews conducted during the inspection, workers at the site expressed freedom to enter safety concerns into the CAP. The inspectors did not identify any impediments to the establishment of a safety conscious work environment at the Prairie Island Nuclear Power Plant.

Cornerstone: Mitigating Systems

Green.

A finding of very low safety significance and associated non-cited violation of Technical Specification Section 5.4.1, Procedures, was identified by the inspectors for the licensees failure to ensure the 21 safeguards diesel exhaust fan main contact connectors were fully engaged and aligned as required per electrical maintenance procedures to ensure proper operation of the breaker. As part of their corrective actions, the licensee aligned and re-engaged the main contact connectors as necessary. In addition, the licensee ensured maintenance personnel were aware of the operating experience to prevent the same issue from occurring in the future. The violation was entered into the licensees corrective action program as Action Request 1525844.

The finding was determined to be more than minor because the finding was associated with the Mitigating Systems Cornerstone and the breaker failure led to the inoperability of the 21 safeguards diesel exhaust fan and impacted the availability of the 22 cooling water system diesel driven pump. This finding represented a loss of the 22 safeguards diesel cooling water pump function for longer than the Technical Specification allowed outage time of 7 days and therefore required a detailed risk evaluation. The regional senior reactor analyst performed a detailed risk evaluation of this finding using the Prairie Island Standardized Plant Analysis Risk Model revision 8.19 and determined the finding was of very low safety significance (Green). The inspectors did not identify a cross-cutting aspect associated with this finding because it was not indicative of current performance. (Section 4OA2.1.b(2)(A))

Green.

A finding of very low safety significance with two examples and an associated non-cited violation of Title 10, Code of Federal Regulations (CFR), Part 50, Appendix B,

Criterion V, Instructions, Procedures, and Drawings, was identified by the inspectors for the licensees failure to accomplish the requirements of procedure FP-OP-OL-01,

Operability/Functionality Determination, Revisions 14 and 15. Specifically, on two occasions, the licensee failed to properly evaluate potential operability concerns associated with the Unit 2 emergency diesel generator (EDG) day tanks and the Unit 2 train A cooling water (CL) system piping. The licensee entered the issues into the Corrective Action Program as Action Requests 1525842 and 1526070 The inspectors determined that the licensees failure to accomplish the requirements of procedure FP-OP-OL-01, Operability/Functionality Determination, Revisions 14 and 15, to properly evaluate the operability issues associated with the Unit 2 EDG day tank fuel oil level and the Unit 2 CL system piping (both safety-related, mitigating systems)was a performance deficiency. The performance deficiency, with two examples, was determined to be more than minor in accordance with Inspection Manual Chapter (IMC) 0612, "Power Reactor Inspection Reports," Appendix B, "Issue Screening," it was associated with the Mitigating Systems Cornerstone attributes of Equipment Performance (for the Unit 2 EDGs) and Protection against External Factors (for the Unit 2 CL piping) 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, and determined that the finding screened as very low safety significance (Green) since the inspectors answered Yes to Question 1 of Section A of Exhibit 2, Mitigating Systems Screening Questions.

The inspectors concluded that this issue was cross-cutting in the area of Problem Identification and Resolution in the aspect of Evaluation. As defined in IMC 0310,

Aspects Within the Cross-Cutting Areas, this aspect states, The organization thoroughly evaluates issues to ensure that resolutions address causes and extent of conditions commensurate with their safety significance. Specifically, the licensee had not thoroughly evaluated the operability issues associated with the Unit 2 EDG day tank levels and the Unit 2 CL piping structural integrity. [P.2](Section 4OA2.1.b(2)(B))

Licensee-Identified Violations

No violations of significance 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 as defined in Inspection Procedure 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 CAP by site personnel.

The inspectors reviewed risk and safety significant issues in the licensees CAP since the last U.S. Nuclear Regulatory Commission (NRC) problem identification and resolution inspection in May 2014. The selection of issues ensured an adequate review of issues across NRC cornerstones. The inspectors used issues identified through NRC generic communications, department self-assessments, licensee audits, operating experience reports, and NRC documented findings as sources to select issues.

Additionally, the inspectors reviewed issue reports (IRs) generated as a result of facility personnels performance in daily plant activities. In addition, the inspectors reviewed IRs and a selection of completed investigations from the licensees various investigation methods, which included root cause evaluations, apparent cause evaluations (ACEs),equipment apparent cause evaluations, causal evaluations, and human performance investigations.

The inspectors selected safety-related heating, ventilation, and air conditioning systems for Units 1 and 2 for a detailed review. The inspectors review was to determine whether the licensee staff properly monitored and evaluated the performance of the system through effective implementation of station monitoring programs. A 5-year review was performed to assess the licensee staffs efforts in monitoring for system degradation due to aging aspects. The inspectors also performed a partial system walkdown of the diesel generator heating, ventilation, and air conditioning systems for Units 1 and 2.

During the reviews, the inspectors determined whether the licensee staffs actions were in compliance with the facilitys CAP and 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 IRs. This included completed investigations and NRC findings, including non-cited violations (NCVs).

b. Assessment

(1) Effectiveness of Problem Identification Based on the results of the inspection, the inspectors concluded that problem identification was generally effective. Based on the information reviewed, the inspectors determined that Prairie Island personnel had a low threshold for initiating IRs; station personnel appropriately screened issues from both the NRC and industry operating experience at an appropriate level and entered them into the CAP when applicable; and identified problems were generally entered into the CAP in a complete, accurate, and timely manner.

The inspectors determined that the station was generally effective at trending low level issues to prevent larger issues from developing. The inspectors determined that the station was trending their unplanned Limiting Condition for Operations (LCOs); however, they had not generated any action requests to evaluate or document trends of unplanned LCOs in 2015. The evaluation of unplanned LCOs was being documented through another process outside of the CAP. The inspectors determined this was a minor administrative issue because the structures, systems, and components that presented the most challenges to unplanned LCOs had either been corrected or corrective actions were planned. The licensee entered the inspectors observation into the CAP as AR 1526254.

The licensee also used the CAP to document instances where previous corrective actions were ineffective or were inappropriately closed.

Findings No findings were identified.

(2) Effectiveness of Prioritization and Evaluation of Issues Based on the results of the inspection, the inspectors concluded that identified problems were generally prioritized and evaluated commensurate with their safety significance, including an appropriate consideration of risk. Higher level evaluations, such as root cause evaluations and ACEs were generally technically accurate; of sufficient depth to effectively identify the cause(s); and adequately considered extent of condition, generic implications, and previous occurrences.

The inspectors identified that in some instances, as allowed per CAP procedures, the licensee assigned causal evaluations versus ACEs based on understanding the direct (or immediate known) cause of an issue or event. Assigning this lower level evaluation could lead to fixing the direct cause of problems (i.e. broke-fix), not identifying the underlying contributors, and could potentially make the station susceptible to repeat events. The vulnerability of the CAP to this potential and the examples where this occurred were shared with station management. The licensee documented the inspectors observations into the CAP as AR 1526252.

The inspectors determined that the CAP pre-screening and screening meetings were generally thorough and meeting participants were actively engaged and well-prepared and accurately prioritized issues.

The inspectors determined that overall, Prairie Island Station personnel evaluated equipment operability and functionality requirements adequately after a degraded or non-conforming condition was identified, and appropriate actions were assigned to correct the degraded or non-conforming condition. The inspectors identified some examples where the licensee failed to thoroughly evaluate operability of issues entered in the CAP. Examples of these issues are documented in the findings below.

Findings (A) Failure to Ensure Breaker Main Contacts are Fully Aligned

Introduction:

A finding of very low safety significance (Green) and associated NCV of Technical Specification (TS) Section 5.4.1, Procedures, was identified by the inspectors for the licensees failure to ensure the 21 safeguards diesel exhaust fan main contact connectors were fully engaged and aligned to ensure proper operation of the breaker, as required by licensee procedure PE MCC-G7, MCC Electrical Preventive Maintenance for GE 7700 Line MCCs.

Description:

On April 1, 2016, the 21 safeguards diesel exhaust fan failed to start during performance of surveillance procedure 1106B, 22 Diesel Cooling Water Pump Monthly Test. The 21 safeguards diesel exhaust fan provides the roof exhaust in the screenhouse when the 22 safeguards diesel drivel cooling water pump is in operation and room temperature is above 60oF. Investigation by the licensee revealed the lower spring-loaded connector for the main contactor on breaker 121C-25 (for the 21 safeguards diesel exhaust fan) was not properly aligned or fully engaged. As a corrective action, maintenance personnel aligned and fully engaged the connector. The licensee tested the breaker by cycling the breaker several times.

The licensee identified that preventative maintenance was last performed on breaker 121C-25 on May 1, 2014. Based on the as-found condition of the breaker, the licensee surmised that the spring-loaded connector for the main contactor was not properly aligned and fully engaged during the breaker maintenance in 2014. The licensees causal evaluation did not thoroughly evaluate the cause of the connectors not being fully engaged during the maintenance activity (i.e. procedural issue, human performance, post-maintenance testing, etc.).

The inspectors reviewed the work order that performed the maintenance in 2014.

Procedure PE MCC-G7, MCC Electrical Preventive Maintenance for GE 7700 Line MCCs, Step 7.5.3 D.2 states, Inspect the main stationary contacts for proper alignment and realign as needed. Discussions with maintenance personnel identified that installing the spring-loaded connectors does entail some skill-of-the-craft work. Proper alignment of the connectors would include ensuring that the connectors are fully engaged.

The licensee determined that there were no past operability concerns for the cooling water pumps based on the exhaust fan failure on April 1, 2016. The inspectors reviewed the licensees past operability review and had some concerns with the licensees conclusions. The inspectors review and investigation indicated that the movement of the spring loaded connectors for the main contactor was due to the connectors not being fully engaged. In addition, the most likely cause of the movement of the connector was due to operation of the breaker, which would have caused the most significant mechanical agitation and vibration on the breaker. The last successful surveillance was completed on March 4, 2016. The inspectors determined that the breaker connectors lost connection with the contactor either after opening on March 4, or upon attempting to close on April 1, 2016. In either case, the failure of the breaker was dependent on breaker operation. The inspectors engineering judgment indicated the breaker was not operable after the breaker opened on March 4, 2016. Therefore, the 21 exhaust fan was inoperable for 28 days (and made the 22 safeguards diesel cooling water pump inoperable), which is longer than the 7 day TS-allowed outage time for the 22 diesel driven cooling water pump.

Analysis:

The inspectors determined that failure to ensure the main contact connectors were fully engaged and aligned as necessary to ensure proper operation of the breaker, was contrary to PE MCC-G7, MCC Electrical Preventive Maintenance for GE 7700 Line MCCs, Revision 38 and was a performance deficiency.

The finding was determined to be more than minor because the finding was associated with the Mitigating Systems Cornerstone attribute of Human Performance and affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e. core damage). Specifically, the breaker failure led to the inoperability of the 21 safeguards diesel exhaust fan and impacted the availability of the 22 cooling water system diesel driven pump.

The inspectors determined the finding could be evaluated using the Significance Determination Process (SDP) in accordance with Inspection Manual Chapter (IMC) 0609, Significance Determination Process, Appendix A, The Significance Determination Process (SDP) For Findings At-Power, Exhibit 2, Mitigating System Screening Questions, because the finding was associated with the Mitigating Systems Cornerstone. This finding represented a loss of the 22 safeguards diesel cooling water pump function for longer than the TS-allowed outage time of 7 days, and therefore required a detailed risk evaluation.

The regional senior reactor analyst (SRA) performed a detailed risk evaluation of this finding using the Prairie Island Standardized Plant Analysis Risk Model (SPAR)revision 8.19. The SRA assumed a safeguards screen house exhaust fan was in a failed condition for an exposure period of 28 days. The calculated delta core damage frequency (CDF) was approximately 3E-7/yr. The dominant core damage sequence was loss of offsite power followed by common cause failure of both safeguards screen house exhaust fans which ultimately results in the loss of seal cooling and a subsequent seal leak. Power is not restored before core damage occurs. The SRA determined that the calculated delta CDF was conservative because there is additional time available to restore offsite power because the cooling water pumps would not fail immediately upon the loss of exhaust fans. As a result of this conservatism, the SRA concluded that the external event and large early release risk contributions were unlikely to significantly contribute to the risk significance of the finding and did not need to be reviewed further.

The result of the detailed risk evaluation is a finding of very low safety significance (Green).

The inspectors did not identify a cross-cutting aspect associated with this finding because it was not indicative of current performance.

Enforcement:

Technical Specification Section 5.4.1 states, in part, that written procedures shall be established, implemented, and maintained covering the applicable procedures recommended in Regulatory Guide 1.33, Revision 2, Appendix A, February 1978.

NRC Regulatory Guide 1.33, Appendix A, Section 9 addresses Procedures for the Performance of Maintenance and states, Maintenance that can affect the performance of safety-related equipment should be properly pre planned and performed in accordance with written procedures and documented instructions appropriate to the circumstances.

Procedure PE MCC-G7, Step 7.5.3 D.2, states, Inspect the main stationary contacts for proper alignment and realign as necessary.

Contrary to the above, on May 1, 2014, the licensee failed to implement Step 7.5.3 D.2 of procedure PE MCC-G7. Specifically, maintenance technicians failed to ensure the main contacts were fully engaged and aligned as necessary.

As part of their corrective actions, the licensee aligned and re-engaged the main contact connectors as necessary. In addition, the licensee ensured maintenance personnel were aware of the operating experience to prevent the same issue from occurring in the future. This violation is being treated as an NCV, consistent with Section 2.3.2 of the Enforcement Policy. The violation was entered into the licensees CAP as AR 1525844.

(NCV 05000282/2016007-01; 05000306/2016007-01, Failure to Ensure Breaker Main Contacts are Fully Aligned)

(B) Improper Operability Determinations

Introduction:

The inspectors identified a finding of very low safety significance (Green)and an associated NCV of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the licensees failure to accomplish the requirements of procedure FP-OP-OL-01, Operability/Functionality Determination, Revisions 14 and 15. Specifically, on two occasions, the licensee failed to properly evaluate potential operability concerns on the Unit 2 emergency diesel generator (EDG) day tanks and the Unit 2 train A cooling water (CL) system piping. The licensee entered the issues into the Corrective Action Program (CAP) as action requests (ARs) 1525842 and 1526070.

The inspectors concluded that this issue was cross-cutting in the area of Problem Identification and Resolution in the aspect of Evaluation. As defined in IMC 0310, Aspects Within the Cross-Cutting Areas, this aspect means The organization thoroughly evaluates issues to ensure that resolutions address causes and extent of conditions commensurate with their safety significance. Specifically, the licensee had not thoroughly evaluated the operability issues associated with the Unit 2 EDG day tank levels and the Unit 2 CL piping structural integrity. [P.2]

Description:

For example 1, on September 23, 2015, the licensee identified that the minimum required fuel level for the Unit 2 EDG day tanks was higher than the value required by the bases for Technical Specification (TS) Surveillance Requirement (SR) 3.8.1.4. Additionally, the licensee also identified that the day tank lower limit switch was inconsistent with the minimum required tank volume as stated in the SR 3.8.1.4 bases. This issue was documented in the CAP as a condition adverse to quality in AR 1494324.

Surveillance Requirement 3.8.1.4 required that every 31 days the licensee verify that the level in each of the Unit 2 EDG day tanks was above the lower limit switch set point. Per the associated Bases, this set point equated to about 425 gallons, which was sufficient to run the Unit 2 EDGs for 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> at full load prior to the actuation of the fuel oil transfer system. This requirement was also consistent with Section 8.4.1 (EDG Design Basis) of the Updated Safety Analysis Report (USAR), Revision 34. This section specifically stated that, Sufficient fuel is stored in the day tank for each Unit 2 EDG for at least 60 minutes of operation at the level where oil is automatically added to the day tank based on the fuel consumption at a load of 100% of the continuous rating of the EDG plus a minimum margin of 10% per ANSI N195-1976.

The licensee identified that the actual minimum tank volume should be approximately 483 gallons (based on higher than expected fuel consumption rates) to meet the SR bases and USAR requirements and that the current lower level switch set point actually resulted in a minimum tank volume of 423 gallons. This raised a current operability issue with the Unit 2 EDGs, as well as a past operability issue given the incorrect lower level switch set point.

In accordance with procedure FP-OP-OL-01, Operability/Functionality Determination, Revision 14, steps 5.3 and 5.4, the Shift Manager initiated an Immediate and then a Prompt Operability Determination (POD), to evaluate the current and past operability concerns and determine any necessary corrective actions. The POD concluded that the Unit 2 EDGs were Operable, but Non-Confirming, and assigned a corrective action to evaluate the necessary actions to resolve the non-conforming condition.

On June 21, 2016, the inspectors identified that the operability conclusion was flawed in that it was based on the ability of the fuel oil transfer system to automatically fill the day tanks once the EDG was started, thereby ensuring that the EDG mission time was met.

The assessments did not address the specific concern which was whether the current or past day tank levels were acceptable or whether the failure to meet the SR 3.8.1.4 and USAR Section 8.4.1 requirements constituted an operability concern. Additionally, the inspectors noted that there were no specific actions in the CAP to address the non-conforming condition identified in the POD. This was considered a failure to meet the requirements of procedure FP-OP-OL-01 in that the current and past operability concerns were not evaluated and the non-confirming condition was not corrected.

The licensee subsequently documented this failure as AR 1525842 and initiated actions to redo the operability assessment, determine the appropriate corrective actions and evaluate why and how the issue occurred. In addition, the licensee verified that the current and past Unit 2 EDG day tank levels met the SR 3.8.1.4 requirements and instituted compensatory actions to daily verify EDG tank levels. These actions were reviewed by the inspectors; no concerns were identified.

For example 2, on October 12, 2015, the licensee identified a through-wall leak on a weld located between two 10 inch elbows on the Unit 2 train A CL system piping. This issue was documented in the CAP as a condition adverse to quality in AR 1496486. In accordance with procedure FP-OP-OL-01, revision 15, steps 5.3 and 5.4, the licensee performed a POD, which concluded the system was inoperable, requiring that a past operability review (POR) be performed in accordance with Step 5.3 of FP-OP-OL-01.

The licensee subsequently repaired the affected section of piping restoring the Unit 2 train A CL system to operable status.

On June 23, 2016, the inspectors identified that the required POR of the Unit 2 train A CL piping had not been adequately performed. Specifically, there was no evaluation in the POR of how the existing pipe flaw (i.e., through wall leak) would have affected the piping structural integrity had a design basis seismic event occurred during past periods of plant operation. Subsequently, the licensee performed a preliminary qualitative assessment which determined that the piping structural integrity would have been maintained had a design basis seismic event occurred. The inspector reviewed the licensees assessment and had no concerns. However, the failure to perform the adequate POR was considered another example of not following the requirements of procedure FP-OP-OL-01. The licensee subsequently documented this failure as AR 1526070 and initiated actions to update the POR to include the past operability of the CL piping structural integrity during design basis seismic events.

Analysis:

The inspectors determined that the licensees failure to properly evaluate and correct the operability issues identified with the Unit 2 EDG day tank fuel oil level and the Unit 2 CL system piping (both safety-related, mitigating systems) in accordance with station procedure FP-OP-OL-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 it was associated with the Mitigating Systems Cornerstone attributes of Equipment Performance (for the Unit 2 EDGs) and Protection against External Factors (for the Unit 2 CL piping) and adversely affected the Cornerstone objective of ensuring the availability, reliability, and capability for mitigating systems to respond to initiating events. Specifically, the licensee failed to ensure that the Unit 2 EDGs and the CL system were operable and able to perform their respective mitigating system 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). Specifically, the inspectors answered Yes to Question 1 of Section A of Exhibit 2, Mitigating Systems Screening Questions, which stated, If the finding is a deficiency affecting the design or qualification of a mitigating SSC, does the SSC maintain its operability or functionality? For both examples, the licensee was able to subsequently demonstrate that the respective systems were operable and therefore would have performed their mitigating system functions.

The inspectors concluded that this issue was cross-cutting in the area of Problem Identification and Resolution in the aspect of Evaluation. As defined in IMC 0310, Aspects Within the Cross-Cutting Areas, this aspect states, The organization thoroughly evaluates issues to ensure that resolutions address causes and extent of conditions commensurate with their safety significance. Specifically, the licensee had not thoroughly evaluated the operability issues associated with the Unit 2 EDG day tank levels and the Unit 2 CL piping structural integrity. [P.2]

Enforcement:

10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, requires, in part, that activities affecting quality be prescribed by documented procedures of a type appropriate to the circumstances and be accomplished in accordance with these procedures. The licensee established FP-OP-OL-01, Operability/Functionality Determination, Revision 14 and 15, as the implementing procedure for determining operability and functionality of Systems, Structures and Components (SSC) described in the TS or credited in the Current Licensing Basis (CLB), an activity affecting quality.

Procedure FP-OP-OL-01, Operability/Functionality Determination, Revisions 14 and 15, Step 5.3, Operability/Functionality/Reportability (OFR) Screening, states, in part:

(1) If the Shift Manager (or designee) discovers or receives notice that an SSC described in the CLB is affected by a degraded, nonconforming, unanalyzed condition or credible new information the Shift Manager (or designee) shall:

Direct that an AR be initiated for the condition if one does not already exist; and Perform OFR screening using instructions in attachment 5, unless the AR description clearly indicates the status of Operability or Functionality, i.e.,

operable or inoperable.

(2) If an Immediate Operability Evaluation is required, then the Shift Manager (or designee) follow the instructions in Section 5.4;

(3) If a Past Operability Review is required, then Engineering follows instructions in section 5.7 Step 5.4 Immediate Operability Determination, sub step 10 states: The Shift Manager shall request a Prompt Operability Determination when, in the Shift Managers judgement, additional information is warranted to support or confirm the Immediate Operability Determination.

Contrary to the above, on two occasions, the licensee failed to perform operability evaluations as required by procedure FP-OP-OL-O1. Specifically:

• On September 23, 2015, the licensee failed to perform an operability evaluation to address an operability concern with the Unit 2 EDGs, as required by Step 5.3 and 5.4 of procedure FP-OP-OL-01, Revision 14. Specifically, neither the Immediate nor Prompt Operability Determinations addressed whether the current or past Unit 2 EDG day tank levels were acceptable or whether the failure to meet the SR 3.8.1.4 and USAR Section 8.4.1 requirements constituted an operability concern.

• On October 22, 2015, the licensee failed to perform an adequate Past Operability Review associated with the Unit 2 CL piping, as required by Step 5.3(3) of procedure FP-OP-OL-01, Revision 15. Specifically, there was no evaluation in the Past Operability Review of how the existing pipe flaw (i.e., through wall leak)would have affected the piping structural integrity had a design basis seismic event occurred during past periods of plant operation.

As stated above, the licensee entered both examples into the CAP (ARs 1525842 and 1526070) and subsequently verified that both the Unit 2 EDGs and CL systems were operable. Because this violation was of very low safety significance and was entered into the licensees CAP, this violation is being treated as a Non-Cited Violation Consistent with Section 2.3.2 of the NRC Enforcement Policy. (NCV 05000282/2016007-02; 05000306/2016007-02, Inadequate Operability Determinations)

(3) Effectiveness of Corrective Actions Based on the results of the inspection, overall, the corrective actions reviewed were found to be appropriately focused to correct the identified problem and were implemented in a timely manner commensurate with the issues safety significance.

Problems identified through root or apparent cause evaluations were resolved in accordance with the CAP procedural and regulatory requirements. Corrective actions intended to prevent recurrence were generally comprehensive, thorough, and timely.

The corrective actions associated with selected NRC documented findings and violations, as well as licensee-identified violations, were generally appropriate to correct the problem and were implemented in a timely manner.

c. Findings

No findings were identified.

.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, attended CAP meetings to observe the use of OE information, completed evaluations of OE issues and events, and selected monthly assessments of the OE composite performance indicators. The inspectors review was performed 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 and timely implemented.

b. Assessment In general, OE was appropriately used at the station. The inspectors observed that OE was discussed as part of the daily station and pre-job briefings. Industry OE was disseminated across the various plant departments. No issues were identified during the inspectors review of licensee OE evaluations. The inspectors also verified that the use of OE in formal CAP products such as root cause evaluations and equipment apparent cause evaluations was appropriate and adequately considered. Generally, OE that was applicable to Prairie Island Station was thoroughly evaluated and actions were implemented in a timely manner to address any issues that resulted from the evaluations.

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 program, prioritize and evaluate issues, and implement effective corrective actions, through efforts from departmental assessments and audits.

b. Assessment Based on the results of the inspection, the inspectors did not identify any issues of concern regarding Prairie Island Station staffs ability to conduct self-assessments and audits. Assessments were conducted in accordance with plant procedures, were generally thorough and intrusive, adequately covered the subject area, and were effective at identifying issues and enhancement opportunities at an appropriate threshold. Identified issues were entered into the CAP with an appropriate significance characterization and corrective actions were completed and/or scheduled to be completed in a timely manner commensurate with their safety significance.

Findings No findings were identified.

.4 Assessment of Safety Conscious Work Environment

a. Inspection Scope

The inspectors assessed the licensees safety conscious work environment through the reviews of the facilitys employee concern program implementing procedures, discussions with coordinators of the employee concern program, interviews with personnel from various departments, and reviews of issue reports. In order to assess Prairie Island safety culture, interviews were conducted with a representative group of station employees over the course of the first and third weeks of the inspection.

Additionally, the sites most recent safety culture assessment was reviewed and the Employee Concerns Program coordinators were interviewed.

b. Assessment Based on the results of the inspection, the inspectors did not identify any issues that suggested conditions were not conducive to the establishment and existence of a safety conscious work environment at Prairie Island Station. Information obtained during the interviews indicated that an environment was established where Prairie Island Station employees felt free to raise nuclear safety issues without fear of retaliation; were aware of and generally familiar with the CAP and other processes, including the Employee Concerns Program and the NRC, through which concerns could be raised; and safety significant issues could be freely communicated to supervision.

c. Findings

No findings were identified.

4OA6 Management Meeting

.1 Exit Meeting Summary

On June 24, 2016, the inspectors presented the inspection results to Mr. S. Northard 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

S. Northard, Site Vice President

N. Abney, Operations Training Instructor

T. Borgen, Operations Manager

J. Bremer, Security Supervisor

H. Butterworth, Director Business Support

A. Chladil, Nuclear Oversight Manager

T. Conboy, Director Site Operations

J. Erickson, Employee Concerns Program

L. Jensen, Performance Improvement

P. Johnson, Regulatory Affairs

J. Kivi, Regulatory Affairs Manager

J. Loesch, Operations

S. Martin, Performance Improvement Manager

T. Wadley, Training Manager

U.S. Nuclear Regulatory Commission

M. Jones, Reactor Inspector

L. Haeg, Senior Resident Inspector, Prairie Island

P. LaFlamme, Resident Inspector

R. Murray, Senior Resident Inspector, Quad Cities (Team Lead)

J. Park, Reactor Inspector

K. Riemer, Branch Chief

N. Shah, Project Engineer

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

05000282/2016007-01; NCV Failure to Ensure Breaker Main Contacts are Fully Aligned

05000306/2016007-01 (Section 4OA2.1.b(2)(A))

05000282/2016007-02; NCV Inadequate Operability Determinations

05000306/2016007-02 (Section 4OA2.1.b(2)(B))

Closed

05000282/2016007-01; NCV Failure to Ensure Breaker Main Contacts are Fully Aligned

05000306/2016007-01 (Section 4OA2.1.b(2)(A))

05000282/2016007-02; NCV Inadequate Operability Determinations

05000306/2016007-02 (Section 4OA2.1.b(2)(B))