IR 05000333/2014005

IR 05000333-14-005; 10/01/2014 - 12/31/2014; James A. FitzPatrick Nuclear Power Plant (Fitzpatrick); Operability Determinations and Functionality Assessments, Follow-Up of Events

ML15037A280
Person / Time
Site:	FitzPatrick
Issue date:	02/06/2015
From:	Arthur Burritt Reactor Projects Branch 2
To:	Brian Sullivan Entergy Nuclear Northeast
Burritt A
References
IR 2014005
Download: ML15037A280 (36)

Text

ary 6, 2015

SUBJECT:

JAMES A. FITZPATRICK NUCLEAR POWER PLANT - NRC INTEGRATED INSPECTION REPORT 05000333/2014005

Dear Mr. Sullivan:

On December 31, 2014, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your James A. FitzPatrick Nuclear Power Plant (FitzPatrick). The enclosed inspection report documents the inspection results which were discussed on January 29, 2015, with you and other members of your staff.

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

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

This report documents one Severity Level IV violation and one violation of NRC requirements which was of very low safety significance (Green). Additionally, a licensee-identified violation, which was determined to be of very low safety significance, is listed in this report. However, because of the very low safety significance, and because they are entered into your corrective action program, the NRC is treating these findings as non-cited violations, consistent with Section 2.3.2.a of the NRC Enforcement Policy. If you contest the non-cited violations in this report, 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 I; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at FitzPatrick. In addition, if you disagree with the cross-cutting aspect assigned to the finding 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 I, and the NRC Resident Inspector at FitzPatrick. In accordance with Title 10 of the Code of Federal Regulations (CFR) 2.390 of the NRCs Rules of Practice, a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRCs Public Document Room or from the Publicly Available Records component of the NRCs Agencywide Documents Access and Management System (ADAMS). ADAMS is accessible from the NRC website at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Arthur L. Burritt, Chief Reactor Projects Branch 2 Division of Reactor Projects Docket No. 50-333 License No. DPR-59

Enclosure:

Inspection Report 05000333/2014005 w/Attachment: Supplementary Information

REGION I==

Docket No. 50-333 License No. DPR-59 Report No. 05000333/2014005 Licensee: Entergy Nuclear Northeast (Entergy)

Facility: James A. FitzPatrick Nuclear Power Plant Location: Scriba, NY Dates: October 1, 2014 through December 31, 2014 Inspectors: E. Knutson, Senior Resident Inspector B. Sienel, Resident Inspector R. Pinson, Project Engineer R. Rolph, Health Physicist Approved by: Arthur L. Burritt, Chief Reactor Projects Branch 2 Division of Reactor Projects Enclosure

SUMMARY

IR 05000333/2014005; 10/01/2014 - 12/31/2014; James A. FitzPatrick Nuclear Power Plant (FitzPatrick); Operability Determinations and Functionality Assessments, Follow-Up of Events.

This report covered a three-month period of inspection by resident inspectors and announced inspections performed by regional inspectors. The inspectors identified one Severity Level (SL)

IV non-cited violation (NCV) and one finding of very low safety significance (Green) which was an NCV. The significance of most 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 (SDP), dated June 2, 2011. 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 July 9, 2013. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 5.

Cornerstone: Mitigating Systems

Severity Level IV. The inspectors identified an SL IV NCV of Title10 of the Code of Federal Regulations (10 CFR) 50.72, Immediate Notification Requirements for Operating Nuclear Power Reactors, because unplanned inoperability of the secondary containment system was not reported to the NRC within eight hours of the occurrence, as required by 10 CFR 50.72(b)(3)(v), Event or Condition that Could Have Prevented Fulfillment of a Safety Function. Specifically, while restoring the normal reactor building ventilation (RBV) system to service following maintenance, reactor building-to-ambient differential pressure dropped below the Technical Specification (TS) required minimum value of 0.25 inches of vacuum water gauge and therefore caused the secondary containment system to be inoperable.

However, FitzPatrick staff did not promptly recognize this as a condition reportable under 10 CFR 50.72. As corrective action, FitzPatrick staff reported the condition to the NRC in accordance with 10 CFR 50.72(b)(3)(v) and entered it into the corrective action program (CAP) as condition report (CR)-JAF-2014-06498.

The inspectors determined that the failure to inform the NRC of the secondary containment system inoperability within eight hours in accordance with 10 CFR 50.72(b)(3)(v) was a performance deficiency that was reasonably within Entergys ability to foresee and correct.

The inspectors evaluated this performance deficiency in accordance with the traditional enforcement process because the issue impacted the regulatory process, in that a safety system functional failure was not reported to the NRC within the required timeframe, thereby delaying the NRCs opportunity to review the matter. Using Example 6.9.d.9 from the NRC Enforcement Policy, the inspectors determined that the violation was a SL IV (more than minor concern that resulted in no or relatively inappreciable potential safety or security consequence) violation, because Entergy personnel failed to make a report required by 10 CFR 50.72 when information that the report was required had been reasonably within their ability to have identified. In accordance with IMC 0612, Power Reactor Inspection Reports, traditional enforcement issues are not assigned cross-cutting aspects. (Section 1R15)

Green.

The inspectors identified a Green NCV for two violations of TS 3.5.1, ECCS

[emergency core cooling systems] - Operating, associated with the non-functionality of east crescent area ventilation and cooling (CAVC) subsystem unit cooler 66UC-22H.

Specifically, during the periods May 5 through May 21, 2010, and March 15 through March 25, 2011, the Technical Requirements Manual (TRM) requirements for east crescent unit cooler operability were not satisfied for longer than the allowed outage time (AOT),

which caused the ECCS in the east crescent to become inoperable and remain so for longer than the TS AOT without completion of the required plant mode changes. As immediate corrective action, Entergy personnel reconditioned the fan motor contactor for the affected unit cooler to obtain satisfactory low voltage pickup response. The issue was entered into Entergys CAP as CR-JAF-2012-00584 and CR-JAF-2012-02288.

The finding was more than minor because it is associated with the Equipment Performance attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the unsatisfactory low voltage response of the 66UC-22H fan motor contactor, along with the unavailability of another east CAVC unit cooler due to maintenance, could have degraded the capability of ECCS systems in the east crescent area during an accident concurrent with degraded voltage conditions. In light of FitzPatrick staffs determination that there was reasonable assurance that the remaining three operable unit coolers would have been capable of removing required post-accident heat loads, the inspectors determined that the finding was of very low safety significance (Green) in accordance with IMC 0609.04, Initial Characterization of Findings, and Exhibit 2 of IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, because the performance deficiency was not a design or qualification deficiency, did not involve an actual loss of safety function, did not represent the actual loss of a safety function of a single train for greater than its TS AOT, and did not screen as potentially risk-significant due to a seismic, flooding, or severe weather initiating event. This finding had a cross-cutting aspect in the area of Problem Identification and Resolution, Resolution, because FitzPatrick staff did not take effective corrective actions to address the low voltage pickup issue in a timely manner commensurate with its safety significance [P.3]. (Section 4OA3)

Other Findings

A violation of very low safety significance that was identified by Entergy was reviewed by the inspectors. Corrective actions taken or planned by Entergy have been entered into the CAP.

The violation and corrective action tracking number are listed in Section 4OA7 of this report.

REPORT DETAILS

Summary of Plant Status

FitzPatrick began the inspection period shut down for refueling outage 21 (RO21) which commenced on August 24, 2014. Operators performed a reactor startup on October 7, 2014.

During the subsequent power escalation on October 9, 2014, with reactor power at 74 percent, a trip of the A reactor water recirculation (RWR) motor-generator (MG) caused the A RWR pump to secure. As a result, operators reduced power to approximately 50 percent for single recirculation loop operations. Following troubleshooting and repair, operators placed the A RWR pump back in service on October 10, 2014, and resumed power ascension. On October 11, 2014, operators increased power to 100 percent, however, the B RWR MG subsequently tripped, and the loss of the B RWR pump caused operators to lower reactor power to approximately 60 percent. Following troubleshooting and repair, operators placed the B RWR pump in service on October 12, 2014, and restored power to 100 percent the following day. However, later on October 13, the B RWR MG again tripped, causing operators to lower reactor power to approximately 60 percent. Following additional troubleshooting and repairs, operators placed the B RWR in service on October 15, 2014. During post-maintenance testing later on October 15, the B RWR MG again tripped, causing operators to lower reactor power to approximately 60 percent. Following additional troubleshooting and repairs, operators placed the B RWR in service on October 18, 2014, and resumed power escalation. On October 19, 2014, operators increased reactor power to 100 percent. On October 20, 2014, operators reduced power to 60 percent for a control rod pattern adjustment and restored power to 100 percent the following day. On December 19, 2014, operators reduced power to 50 percent to support a planned steam leak repair for balance of plant equipment. Operators restored power to 100 percent the following day and remained at or near 100 percent power for the remainder of the inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

.1 Readiness for Seasonal Extreme Weather Conditions

a. Inspection Scope

The inspectors performed a review of FitzPatricks readiness for the onset of seasonal low temperatures. The review focused on the emergency diesel generator (EDG) and EDG room ventilation systems. The inspectors reviewed the Updated Final Safety Analysis Report (UFSAR), TSs, control room logs, and the CAP to determine what temperatures or other seasonal weather could challenge these systems, and to ensure FitzPatrick personnel had adequately prepared for these challenges. The inspectors reviewed station procedures, including FitzPatricks seasonal weather preparation procedure and applicable operating procedures. The inspectors performed walkdowns of the selected systems to ensure station personnel identified issues that could challenge the operability of the systems during cold weather conditions. Documents reviewed for each section of this inspection report are listed in the Attachment.

b. Findings

No findings were identified.

.2 Readiness for Impending Adverse Weather Conditions

a. Inspection Scope

On November 12, 2014, the inspectors reviewed FitzPatricks preparations for high winds due to an arriving weather front. The inspectors walked down exterior portions of the plant to identify loose or inadequately protected equipment and materials. The inspectors verified that the circulating water and service water systems were operated in accordance with procedural requirements for high wind conditions. The plant did not experience any significant operational issues as a result of the high wind conditions.

b. Findings

No findings were identified.

1R04 Equipment Alignment

.1 Partial System Walkdown

a. Inspection Scope

The inspectors performed partial walkdowns of the following systems:

Reactor core isolation cooling (RCIC) system on October 23, 2014 EDG systems during offsite 115 kilovolt (kV) Line 4 outage on October 28, 2014 The inspectors selected these systems based on their risk-significance relative to the reactor safety cornerstones at the time they were inspected. The inspectors reviewed applicable operating procedures, system diagrams, the UFSAR, TSs, CRs, and the impact of ongoing work activities on redundant trains of equipment in order to identify conditions that could have impacted system performance of their intended safety functions. The inspectors performed field walkdowns of accessible portions of the systems to verify system components and support equipment were aligned correctly and were operable. The inspectors examined the material condition of the components and observed operating parameters of equipment to verify that there were no deficiencies.

The inspectors also reviewed whether Entergy staff had properly identified equipment issues and entered them into the CAP for resolution with the appropriate significance characterization.

b. Findings

No findings were identified.

.2 Full System Walkdown

a. Inspection Scope

On October 16, 2014, the inspectors performed a complete system walkdown of accessible portions of the A core spray system to verify the existing equipment lineup was correct. The inspectors reviewed operating procedures, drawings, equipment line-up check-off lists, and the UFSAR to verify the system was aligned to perform its required safety functions. The inspectors also reviewed electrical power availability, component lubrication and equipment cooling, hanger and support functionality, and operability of support systems. The inspectors performed field walkdowns of accessible portions of the system to verify system components and support equipment were aligned correctly and operable. The inspectors examined the material condition of the components and observed operating parameters of equipment to verify that there were no deficiencies. Additionally, the inspectors reviewed a sample of related CRs and work orders (WOs) to ensure Entergy personnel appropriately evaluated and resolved any deficiencies.

b. Findings

No findings were identified.

1R05 Fire Protection

Resident Inspector Quarterly Walkdowns (71111.05Q - 5 samples)

a. Inspection Scope

The inspectors conducted tours of the areas listed below to assess the material condition and operational status of fire protection features. The inspectors verified that Entergy controlled combustible materials and ignition sources in accordance with administrative procedures. The inspectors verified that fire protection and suppression equipment was available for use as specified in the area pre-fire plan, and passive fire barriers were maintained in good material condition. The inspectors also verified that station personnel implemented compensatory measures for out of service, degraded, or inoperable fire protection equipment, as applicable, in accordance with procedures.

Turbine operating floor, turbine building 300 elevation, fire area/zone IE/TB-1 on October 2, 2014 Turbine building 252 elevation, fire area/zone IE/TB-1, on October 24, 2014 A and B battery rooms, battery charger rooms, and corridor, fire area/zones III/BR-1 through BR-5, on November 5, 2014 Reactor building 369 elevation, fire area/zone IX/RB-1A, on November 18, 2014 Cable spreading room, fire area/zone VII/CS-1, on November 20, 2014

b. Findings

No findings were identified.

.2 Fire Protection - Drill Observation

a. Inspection Scope

The inspectors observed an unannounced fire brigade drill conducted on November 25, 2014, that involved a fire in the east cable tunnel. The inspectors evaluated the readiness of the plant fire brigade to fight fires. The inspectors verified that FitzPatrick personnel identified deficiencies, openly discussed them in a self-critical manner at the debrief, and took appropriate corrective actions as required. The inspectors evaluated specific attributes as follows:

Proper wearing of turnout gear and self-contained breathing apparatus Proper use and layout of fire hoses Employment of appropriate fire-fighting techniques Sufficient fire-fighting equipment brought to the scene Effectiveness of command and control Search for victims and propagation of the fire into other plant areas Utilization of pre-planned strategies Adherence to the pre-planned drill scenario Drill objectives met The inspectors also evaluated the fire brigades actions to determine whether these actions were in accordance with FitzPatricks fire-fighting strategies.

b. Findings

No findings were identified.

1R06 Flood Protection Measures

.1 Internal Flooding Review (1 sample)

a. Inspection Scope

The inspectors reviewed the UFSAR, the site flooding analysis, and plant procedures to assess susceptibilities involving internal flooding. The inspectors also reviewed the CAP to determine if Entergy staff identified and corrected flooding problems and whether operator actions for coping with flooding were adequate. The inspectors focused on the east crescent area of the reactor building which contains the high pressure coolant injection (HPCI) system and the A train of the core spray and residual heat removal (RHR) systems, to verify the adequacy of floor and water penetration seals and common drain lines and sumps and level alarms.

b. Findings

No findings were identified.

.2 Annual Review of Cables Located in Underground Bunkers/Manholes (3 samples)

a. Inspection Scope

The inspectors examined manhole MH-7A in the 115 kV switchyard, and manholes MH-8A and MH-8B in the 345 kV switchyard during FitzPatrick staffs annual inspection of manhole sump pumps. These manholes contain non-safety class electrical cables that could affect the reliability of the 115 kV and 345 kV systems. The inspectors verified that cable insulation was not visibly degraded. The inspectors observed that many of the cable trays and supports were corroded. These manholes can be subject to flooding because there are no sump high level alarms to alert operators to a sump pump failure, and there is a history of such failures. The degraded conditions in these manholes did not constitute a violation of regulatory requirements because the manholes do not contain safety-related equipment.

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program and Licensed Operator Performance

.1 Quarterly Review of Licensed Operator Requalification Testing and Training

a. Inspection Scope

The inspectors observed licensed operator simulator training on October 22, 2014, which included a feedwater level controller malfunction, a blizzard warning, an onsite explosion, and intake icing. The inspectors evaluated operator performance during the simulated event and verified completion of risk significant operator actions, including the use of abnormal and emergency operating procedures. The inspectors assessed the clarity and effectiveness of communications, implementation of actions in response to alarms and degrading plant conditions, and the oversight and direction provided by the control room supervisor. Additionally, the inspectors assessed the ability of the crew and training staff to identify and document crew performance problems.

b. Findings

No findings were identified.

.2 Quarterly Review of Licensed Operator Performance in the Main Control Room

a. Inspection Scope

On October 7, 2014, the inspectors observed control room operators during the reactor startup following RO21. The inspectors observed the control room operators brief on control rod withdrawal to criticality and portions of the reactor startup, including the approach to and achievement of criticality, power escalation through the intermediate range to the point of adding heat, and heatup. The inspectors observed crew performance to verify that procedure use, crew communications, and coordination of activities between work groups met established expectations and standards.

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

The inspectors reviewed the samples listed below to assess the effectiveness of maintenance activities on structure, system, or component (SSC) performance and reliability. The inspectors reviewed system health reports, CAP documents, and maintenance rule basis documents to ensure that Entergy staff was identifying and properly evaluating performance problems within the scope of the maintenance rule. For each sample selected, the inspectors verified that the SSC was properly scoped into the maintenance rule in accordance with 10 CFR Part 50.65 and verified that the (a)(2)performance criteria established by Entergy staff was reasonable. For SSCs classified as (a)(1), the inspectors assessed the adequacy of goals and corrective actions to return these SSCs to (a)(2). Additionally, the inspectors ensured that Entergy staff was identifying and addressing common cause failures that occurred within and across maintenance rule system boundaries.

direct current electrical distribution containment atmosphere dilution

b. Findings

No findings were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

The inspectors reviewed maintenance activities to verify that the appropriate risk assessments were performed prior to removing equipment for work. The inspectors reviewed whether risk assessments were performed as required by 10 CFR 50.65(a)(4),and were accurate and complete. When emergent work was performed, the inspectors reviewed whether plant risk was promptly reassessed and managed. The inspectors also walked down selected areas of the plant which became more risk significant because of the maintenance activities to ensure they were appropriately controlled to maintain the expected risk condition. The reviews focused on the following activities:

A power reduction to 54 percent for a control rod pattern adjustment, B and D EDG monthly surveillance test, B RHR quarterly surveillance test, and feedwater level controller transient response testing the week of October 20, 2014 Offsite maintenance which required 115 kV Line 4 to be taken out of service the week of October 27, 2014 Planned HPCI system maintenance the week of November 17, 2014

b. Findings

No findings were identified.

1R15 Operability Determinations and Functionality Assessments

a. Inspection Scope

The inspectors reviewed operability determinations for the following degraded or non-conforming conditions:

CR-JAF-2014-06358 concerning turbine first stage pressure indications that were less than the expected value and the possible implication of this to the turbine stop valve closure and turbine control valve fast closure reactor protection system inputs on October 21, 2014 Reviewed FitzPatrick staffs determination that the B emergency service water pump and the B and D RHR service water pumps remained operable while the B safety-related pump room exhaust fan was inoperable for planned maintenance, given that they had reached a different conclusion during an unplanned loss of the same fan earlier this year, as documented in Licensee Event Report (LER)05000333/2014-001-00 on October 28, 2014 CR-JAF-2014-06498 concerning secondary containment operability when differential pressure between the secondary containment and ambient dropped to less than 0.25 inches of vacuum water gauge while switching the RBV lineup on October 28, 2014 The inspectors selected these issues based on the risk significance of the associated components and systems. The inspectors evaluated the technical adequacy of the operability determinations to assess whether TS operability was properly justified and the subject component or system remained available such that no unrecognized increase in risk occurred. The inspectors compared the operability and design criteria in the appropriate sections of the TSs and UFSAR to Entergy staffs evaluations to determine whether the components or systems were operable. Where compensatory measures were required to maintain operability, the inspectors determined whether the measures in place would function as intended and were properly controlled by Entergy staff. The inspectors determined, where appropriate, compliance with bounding limitations associated with the evaluations.

b. Findings

Introduction.

The inspectors identified a SL IV NCV of 10 CFR 50.72, Immediate Notification Requirements for Operating Nuclear Power Reactors, because unplanned inoperability of the secondary containment system was not reported to the NRC within eight hours of the occurrence, as required by 10 CFR 50.72(b)(3)(v), Event or Condition that Could Have Prevented Fulfillment of a Safety Function. Specifically, while restoring the normal RBV system to service following maintenance, reactor building-to-ambient differential pressure dropped below the TS required minimum value of 0.25 inches of vacuum water gauge and therefore caused the secondary containment system to be inoperable. However, FitzPatrick staff did not promptly recognize this as a condition reportable under 10 CFR 50.72.

Description.

On the evening of October 28, 2014, operators commenced restoration of the RBV system to service in accordance with OP-51A, Reactor Building Ventilation and Cooling System, following planned maintenance. During restoration, RBV train A was in service, along with the standby gas treatment (SBGT) system, with secondary containment differential pressure reading 0.5 inches water vacuum. When the SBGT system was secured in accordance with OP-51A, the secondary containment differential pressure lowered to 0.19 inches water vacuum. Operators subsequently isolated the reactor building vent and proceeded to place RBV train B exhaust fans into service.

When 66FN-13B (B train exhaust fan) was started, 66FN-13A (A train exhaust fan)was secured, and secondary containment differential pressure increased to 1.37 inches water vacuum. Operators entered the high secondary containment differential pressure issue into the CAP as CR-JAF-2014-06498.

Evaluation by Entergy personnel determined that 66AOD-106A, a damper downstream of 66FN-13A, did not open as expected when 66FN-13A was running. This prevented exhaust from the reactor building, allowing secondary containment to increase in pressure above the TS Surveillance Requirement (SR) 3.6.4.1.1 allowed value of 0.25 inches water vacuum. Entergy personnel determined that, because 66AOD-106A is not a part of secondary containment and has no safety related function, the condition had not constituted a condition that could have prevented fulfillment of the secondary containment safety function, and therefore was not reportable per 10 CFR 50.72(b)(3)(v), Event or Condition that Could Have Prevented Fulfillment of a Safety Function.

The following day, the inspectors reviewed the secondary containment differential pressure issue. In accordance with NUREG-1022, Event Report Guidelines 10 CFR 50.72 and 50.73, a report is required under 10 CFR 50.72(b)(3)(v) when 1) there is a determination that the system is inoperable in a required mode, 2) the inoperability is due to personnel errors, including equipment failures, and 3) no redundant equipment in the same system was operable. Concerning secondary containment operability, IMC 0326, Operability Determinations & Functionality Assessments for Conditions Adverse to Quality or Safety, states, In order to be considered operable, an SSC must be capable of performing the specified safety functions of its design. In addition, TS operability considerations require that an SSC meet all SRs (as specified in SR Applicability SR 3.0.1). An SSC that does not meet an SR must be declared inoperable because the LCO [limiting condition for operation] operability requirement(s) are not met. Although the secondary containment system would have performed its specified safety functions, the system failed SR 3.6.4.1.1, which requires that secondary containment differential pressure be maintained greater than or equal to 0.25 inches water vacuum. Therefore, the inspectors determined that, for the time period that secondary containment differential pressure was less than 0.25 inches water vacuum, the secondary containment system had been inoperable. Given that the inoperability was due, in part, to equipment failure, and that no redundant equipment was operable, in that the secondary containment system is a single train system, the inspectors concluded that the secondary containment differential pressure issue was reportable under 10 CFR 50.72(b)(3)(v). As corrective action, FitzPatrick staff reported the condition to the NRC in accordance with 10 CFR 50.72(b)(3)(v).

Analysis.

The inspectors determined that the failure to inform the NRC of the secondary containment system inoperability within eight hours in accordance with 10 CFR 50.72(b)(3)(v) was a performance deficiency that was reasonably within Entergys ability to foresee and correct. The inspectors evaluated this performance deficiency in accordance with the traditional enforcement process because the issue impacted the regulatory process, in that a safety system functional failure was not reported to the NRC within the required timeframe, thereby delaying the NRCs opportunity to review the matter. Using Example 6.9.d.9 from the NRC Enforcement Policy, the inspectors determined that the violation was a SL IV (more than minor concern that resulted in no or relatively inappreciable potential safety or security consequence) violation, because Entergy personnel failed to make a report required by 10 CFR 50.72 when information that the report was required had been reasonably within their ability to have identified. In accordance with IMC 0612, Power Reactor Inspection Reports, traditional enforcement issues are not assigned cross-cutting aspects.

Enforcement.

10 CFR 50.72(b)(3)(v)(C) requires, in part, that licensees shall notify the NRC within eight hours of the occurrence of any event or condition that at the time of discovery could have prevented the fulfillment of a safety function of structures or systems that are needed to control the release of radioactive material. Contrary to the above, on October 28, 2014, at 5:08 p.m., indication of secondary containment differential pressure provided information that identified that the secondary containment differential pressure had decreased below the TS SR value of 0.25 inches water vacuum, and therefore, resulted in secondary containment being inoperable. However, this information was not promptly recognized by Entergy personnel and was not reported to the NRC until October 30, 2014, at 1:05 p.m., a period of approximately 44 hours5.092593e-4 days <br />0.0122 hours <br />7.275132e-5 weeks <br />1.6742e-5 months <br />.

Because this SL IV violation was of very low safety significance, was not repetitive or willful, and was placed in Entergys CAP as CR-JAF-2014-06683, it is being treated as an NCV, consistent with Section 2.3.2.a of the Enforcement Policy. (NCV 05000333/2014005-01, Untimely 10 CFR 50.72 Notification of a Secondary Containment System Functional Failure)

1R18 Plant Modifications

.1 Permanent Modification - New Design for Condensate Storage Tank RCIC Logic Level

Switches

a. Inspection Scope

The inspectors evaluated a modification to the RCIC system implemented by engineering change (EC) 47824, Evaluate New Design Topworks for CST [condensate storage tank] RCIC Logic Level Switches. In 2013, the RCIC CST logic level switches failed their quarterly surveillance test several times. The modification, processed as an equivalency, was performed to improve the reliability and adjustability of the switches.

The inspectors verified that the design bases, licensing bases, and performance capability of the system were not degraded by the modification. In addition, the inspectors reviewed modification documents associated with the design change, and reviewed the 10 CFR 50.59 screening.

b. Findings

No findings were identified.

.2 Permanent Modification - A Main Station Battery Replacement

a. Inspection Scope

The inspectors evaluated a modification to the 125-volt direct current electrical system implemented during RO21 by EC 38334, Replace A 125-Volt Station Battery, 71SB-1.

This change was implemented because the existing A station battery was approaching the end of its life expectancy. The EC also slightly increased the battery capacity to provide longer capability during a station blackout event. It did so using higher capacity cells which have one additional positive and negative plate, but are otherwise functionally equivalent to the old battery cells. The inspectors verified that the design bases, licensing bases, and performance capability of the affected system were not degraded by the modification. In addition, the inspectors reviewed modification documents associated with the design change, and performed a walkdown of the new A station battery.

b. Findings

No findings were identified.

.3 Permanent Modification - Replacement of Main Condenser Tubing

a. Inspection Scope

The inspectors evaluated a modification of the main condenser to replace all existing circulating water tubes with titanium tubes, implemented during RO21 by EC 40597, Replacement of Main Condenser Tubing. This modification was significant because repetitive leakage from the existing tubes had been the cause of the current White performance indicator for unplanned power changes at FitzPatrick, as discussed in Section 4OA5 of this report. The inspectors verified that the design bases, licensing bases, and performance capability of the main condenser were not significantly affected by the modification. In addition, the inspectors reviewed modification documents associated with the design change, and observed portions of the old tubing removal and new tubing installation.

b. Findings

No findings were identified.

1R19 Post-Maintenance Testing

a. Inspection Scope

The inspectors reviewed the post-maintenance tests (PMTs) for the maintenance activities listed below to verify that procedures and test activities ensured system operability and functional capability. The inspectors reviewed the test procedure to verify that the procedure adequately tested the safety functions that may have been affected by the maintenance activity, that the acceptance criteria in the procedure was consistent with the information in the applicable licensing basis and/or design basis documents, and that the procedure had been properly reviewed and approved. The inspectors also witnessed the test or reviewed test data to verify that the test results adequately demonstrated restoration of the affected safety functions.

WO 52474146-03 to verify proper source range monitor (SRM) to intermediate range monitor (IRM) indication overlap following replacement of all SRM and IRM detectors; performed during the reactor startup at the conclusion of RO21, in accordance with ST-5G, SRM-IRM Overlap Verification, on October 7, 2014 Observed startup of B RWR pump as PMT for MG maintenance following the second B pump trip on October 16, 2014 Reviewed ST-8Q, Testing of the Emergency Service Water System (IST [inservice test]), Revision 44, partially performed October 22-30, 2014, as PMT for cleaning of east crescent area unit cooler 66UC-22H performed under WO 52350312, on November 4, 2014 WO 52253258 to replace rod withdraw permissive relay 03A-K6, on November 12, 2014 WO 52342513 to perform major preventive maintenance on HPCI pump suction valve, 23MOV-17, operator on November 20, 2014 WO 52428707 to perform a flush and inspection of the HPCI governor remote servo, 23HYC-1, on November 20, 2014

b. Findings

No findings were identified.

1R20 Refueling and Other Outage Activities

a. Inspection Scope

The inspectors reviewed FitzPatricks implementation of RO21 outage plans and schedules to verify that risk, industry experience, previous site specific problems, and defense-in-depth were considered. During the outage, the inspectors observed portions of the startup process and monitored controls associated with the following outage activities:

Configuration management, including maintenance of defense-in-depth, commensurate with the outage plan for the key safety functions and compliance with the applicable TS when taking equipment out of service Installation and configuration of reactor coolant pressure, level, and temperature instruments to provide accurate indication and instrument error accounting Status and configuration of electrical systems and switchyard activities to ensure that TSs were met Monitoring of decay heat removal operations Impact of outage work on the ability of the operators to operate the spent fuel pool cooling system Reactor water inventory controls, including flow paths, configurations, alternative means for inventory additions, and controls to prevent inventory loss Activities that could affect reactivity Maintenance of secondary containment as required by TS Refueling activities, including full core verification Fatigue management Containment closeout inspection Identification and resolution of problems related to refueling outage activities

b. Findings

No findings were identified.

1R22 Surveillance Testing

a. Inspection Scope

The inspectors observed performance of surveillance tests and/or reviewed test data of selected risk-significant SSCs to assess whether test results satisfied TSs, the UFSAR, and station procedure requirements. The inspectors verified that test acceptance criteria were clear, tests demonstrated operational readiness and were consistent with design documentation, test instrumentation had current calibrations and the range and accuracy for the application, tests were performed as written, and applicable test prerequisites were satisfied. Upon test completion, the inspectors considered whether the test results supported that equipment was capable of performing the required safety functions. The inspectors reviewed the following surveillance tests:

ST-24J, RCIC Flow Rate and Inservice Test (IST), on October 7, 2014 ST-2AL, RHR Loop A Quarterly Operability Test (IST), on November 3, 2014 ISP-175A1, Reactor and Containment Cooling Instrument Functional Test/

Calibration (ATTS [analog transmitter trip system])**, on November 5, 2014 ST-24E, RCIC Logic System Functional and Simulated Automatic Actuation Test, on December 2, 2014

b. Findings

No findings were identified.

2RS1 Radiological Hazard Assessment and Exposure Controls

a. Inspection Scope

The inspectors reviewed Entergy staffs performance in assessing and controlling radiological hazards in the workplace. The inspectors used the requirements contained in 10 CFR 20, TSs, applicable Regulatory Guides, and procedures required by TSs as criteria for determining compliance.

Inspection Planning

The inspectors reviewed 2014 Entergy performance indicators for the occupational exposure cornerstone for Fitzpatrick.

Radiological Hazards Control and Work Coverage The inspectors assessed whether dosimetry was placed in the location of highest expected dose or that Entergy staff properly implemented an NRC-approved method of determining effective dose equivalent.

The inspectors reviewed the application of dosimetry to effectively monitor exposure to personnel in high-radiation work areas with significant dose rate gradients.

The inspectors reviewed radiation work permit (RWP) number 20140701 for work within an airborne radioactivity area with the potential for individual worker internal exposures.

For this RWP, the inspectors evaluated airborne radioactive controls and monitoring, including potential for significant airborne levels. The inspectors assessed applicable containment barrier integrity and the operation of temporary high-efficiency particulate air ventilation systems.

b. Findings

No findings were identified.

2RS2 Occupational ALARA Planning and Controls

a. Inspection Scope

The inspectors assessed performance with respect to maintaining occupational individual and collective radiation exposures as low as is reasonably achievable (ALARA). The inspectors used the requirements contained in 10 CFR 20, applicable Regulatory Guides, TSs, and procedures required by TSs as criteria for determining compliance.

Inspection Planning

The inspectors reviewed pertinent information regarding FitzPatrick collective dose history, current exposure trends, and ongoing or planned activities in order to assess current performance and exposure challenges. The inspectors reviewed the plants three year rolling average collective exposure.

The inspectors compared the site-specific trends in collective exposures against the industry average values and those values from similar vintage reactors. In addition, the inspectors reviewed any changes in the radioactive source term by reviewing the trend in average contact dose rate with recirculation piping.

Radiological Work Planning The inspectors selected the following work activities for review based on exposure significance:

Reactor Disassembly/Reassembly Activities Reactor Water Cleanup Work RO21 Drywell In-service Inspection/Flow Accelerated Corrosion Drywell Scaffold Support Condenser Re-tube Project The inspectors compared the results achieved (dose rate reductions, actual dose) with the intended dose established in Entergy ALARA planning for these work activities. The inspectors compared the person-hour estimates provided by maintenance planning and other groups to the Radiation Protection group actual person-hours for the work activity and evaluated the accuracy of these time estimates. The inspectors assessed the causes for any inconsistencies between intended and actual work activity doses.

The inspectors determined whether post-job reviews were conducted to identify lessons learned and that they were entered into Entergys CAP.

Source Term Reduction and Control The inspectors reviewed Entergys records to determine the historical trends and current status of plant source term that affect facility collective dose. The inspectors assessed whether the licensee had developed contingency plans for expected changes in the source term as the result of changes in plant fuel performance issues or changes in plant primary chemistry.

b. Findings

No findings were identified.

2RS5 Radiation Monitoring Instrumentation

a. Inspection Scope

The inspectors reviewed the accuracy and operability of radiation monitoring instruments that were used to protect occupational workers. The inspectors used the requirements in 10 CFR 20, applicable Regulatory Guides and industry standards, TSs, and procedures required by TSs as criteria for determining compliance.

Post-Accident Monitoring Instrumentation Inspectors reviewed the calibration documentation for the drywell high-range radiation monitors. The inspectors selected one effluent/process monitor that was referenced in Entergys emergency operating procedures and evaluated the calibration and availability of this instrument.

b. Findings

No findings were identified.

4OA1 Performance Indicator Verification

Occupational Exposure Control Effectiveness

a. Inspection Scope

The inspectors sampled Entergys submittals for the occupational exposure control effectiveness performance indicator for the period from the fourth quarter 2013 through third quarter 2014. The inspectors used performance indicator definitions and guidance contained in the Nuclear Energy Institute Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, to determine the accuracy of the performance indicator data reported.

To assess the adequacy of Entergys performance indicator data collection and analyses, the inspectors discussed with radiation protection staff the scope and breadth of its data review and the results of those reviews. The inspectors independently reviewed electronic personal dosimetry accumulated dose alarms, dose reports, and dose assignments for any intakes that occurred during the time period reviewed to determine if there were potentially unrecognized performance indicator occurrences.

The inspectors also conducted walkdowns of numerous locked high and very high radiation area entrances to determine the adequacy of the controls in place for these areas.

b. Findings

No findings were identified.

4OA2 Problem Identification and Resolution

.1 Routine Review of Problem Identification and Resolution Activities

a. Inspection Scope

As required by Inspection Procedure (IP) 71152, Problem Identification and Resolution, the inspectors routinely reviewed issues during baseline inspection activities and plant status reviews to verify that Entergy staff entered issues into the CAP at an appropriate threshold, gave adequate attention to timely corrective actions, and identified and addressed adverse trends. In order to assist with the identification of repetitive equipment failures and specific human performance issues for follow-up, the inspectors performed a daily screening of items entered into the CAP and periodically attended CR screening meetings.

b. Findings

No findings were identified.

.2 Semi-Annual Trend Review (1 sample)

a. Inspection Scope

The inspectors performed a semi-annual review of site issues, as required by IP 71152, Problem Identification and Resolution, to identify trends that might indicate the existence of more significant safety issues. In this review, the inspectors included repetitive or closely-related issues that may have been documented by Entergy outside of the CAP, such as trend reports, performance indicators, system health reports, and CAP backlogs. The inspectors also reviewed Entergys CAP database for the third and fourth quarters of 2014 to assess CRs written in various subject areas (equipment problems, human performance issues, etc.), as well as individual issues identified during the NRCs daily CR review (Section 4OA2.1). The inspectors reviewed Entergys Aggregate Performance Review Meeting Report for the third quarter of 2014, conducted under EN-LI-121, Trending and Performance Review Process, to verify that Entergy personnel were appropriately evaluating and trending adverse conditions in accordance with applicable procedures.

b. Findings and Observations

No findings were identified.

The inspectors evaluated a sample of CRs generated over the course of the past two quarters by departments that provide input to the quarterly Aggregate Performance Review. The inspectors determined that, in most cases, the issues were appropriately evaluated by Entergy staff for potential trends and resolved within the scope of the CAP.

However, the inspectors noted one instance where issue trending was not utilized and may have been useful, and that was in the area of maintenance and test equipment (M&TE) calibration. The inspectors noted that at least 22 pieces of M&TE had been found to be out of tolerance during regularly scheduled calibration, thereby requiring evaluation as to whether their previous use had possibly affected or invalidated the results of required activities such as surveillances. Review of CRs from the first two quarters of 2014 revealed similar results, with at least 21 pieces of M&TE having been found out of tolerance. However, this issue was not included in the most recent Aggregate Performance Review Meeting Report. The inspectors considered that this example represented a missed opportunity to effectively use all of the tools available in the CAP.

.3 Annual Sample: Review of the Operator Workaround Program (1 sample)

a. Inspection Scope

The inspectors reviewed the cumulative effects of the existing operator workarounds, operator burdens, operator aids and disabled alarms, and open main control room deficiencies to identify any effect on emergency operating procedure operator actions, and any impact on possible initiating events and mitigating systems. The inspectors evaluated whether station personnel had identified, assessed, and reviewed operator workarounds as specified in Entergy Fleet procedure EN-FAP-OP-006, Operator Aggregate Impact Index Performance Indicator.

The inspectors reviewed FitzPatricks process to identify, prioritize, and resolve main control room distractions to minimize operator burdens. The inspectors reviewed the system used to track these operator workarounds and a recent FitzPatrick staff evaluation of the aggregate impact index. The inspectors also routinely toured the control room and discussed operator workarounds with the operators to ensure items were addressed on a schedule consistent with their relative safety significance.

b. Findings and Observations

No findings were identified.

The inspectors determined that the issues reviewed did not adversely affect the capability of the operators to implement abnormal or emergency operating procedures.

The inspectors also verified that FitzPatrick staff entered operator workarounds and burdens into the CAP at an appropriate threshold and planned or implemented corrective actions commensurate with their safety significance.

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

.1 (Closed) LER 05000333/2012-001-00 and -01: Unit Cooler Fan Motor Contactor Low

Voltage Test Failure Results in Loss of Safety Function and Condition Prohibited by the Technical Specifications

a. Inspection Scope

On January 26, 2012, first time low voltage pickup testing was performed for the east CAVC subsystem unit cooler 66UC-22H fan motor contactor. Based on the as-found value, FitzPatrick staff determined that this unit cooler, and therefore the east CAVC subsystem, would not have been able to perform its support function to provide adequate cooling under all conditions, and therefore caused all ECCS in the east crescent to be inoperable. The LER was submitted due to a condition prohibited by the plants TSs, and due to a condition that could have prevented fulfillment of the safety function of a system needed to mitigate the consequences of an accident (specifically, the single train HPCI system).

The original LER was discussed in NRC Integrated Inspection Report 05000333/2012004. At that time, the inspectors had determined that FitzPatrick staffs characterization of the violations associated with this LER was not entirely accurate. As a result, FitzPatrick staff issued revision 1 of this LER to clarify their description of the issue.

b. Findings

Introduction.

The inspectors identified a Green NCV for two violations of TS 3.5.1, ECCS - Operating, associated with the non-functionality of east CAVC subsystem unit cooler 66UC-22H. Specifically, during the periods May 5 through May 21, 2010, and March 15 through March 25, 2011, the Technical Requirements Manual (TRM)requirements for east crescent unit cooler operability were not satisfied for longer than the allowed outage time (AOT), which caused the ECCS in the east crescent to become inoperable and remain so for longer than the TS AOT without completion of the required plant mode changes.

Description.

The purpose of safety-related motor control center contactor minimum pickup voltage testing is to provide assurance that safety-related loads will energize under design basis degraded voltage conditions. The need to perform this testing at FitzPatrick was identified in August 2005; however, rather than verifying the operability of all subject loads by testing at that time, this testing was incorporated into the procedure for periodic (seven year) motor control center electrical component preventative maintenance.

Each of the two CAVC subsystems contains five unit coolers. TRM Section 3.7.C addresses CAVC operability requirements and establishes a minimum of four operable unit coolers for the associated CAVC subsystem to be considered operable.

Additionally, the TRM imposes maximum allowable heat sink (service water)temperatures for operability, based on the thermal performance capabilities of the remaining four unit coolers. If a CAVC subsystem is inoperable, TRM 3.7.C provides an AOT of seven days for the subsystem to be restored to operable status. If the AOT is not met, an operability determination must immediately be performed for the affected ECCS subsystems and the RCIC system.

Revision 1 of the subject LER identified two conditions that, along with 66UC-22H inoperability due to the out-of-specification fan motor contactor low voltage pickup, would cause the east CAVC subsystem to be inoperable: 1) another east CAVC subsystem unit cooler inoperable; and 2) maximum allowable service water temperature for the remaining four east CAVC subsystem unit coolers exceeded. FitzPatrick staff determined that, during the three years prior to identification of the 66UC-22H low voltage pickup issue, there had been two occasions when another east CAVC subsystem unit cooler had been inoperable. Specifically: 66UC-22F had been out of service for planned maintenance from 0300 on May 5, 2010, through 0800 on May 21, 2010, a period of 16 days, 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />; and 66UC-22K had been out of service for planned maintenance from 1027 on March 15, 2011, through 0735 on March 25, 2011, a period of 9 days, 21 hours2.430556e-4 days <br />0.00583 hours <br />3.472222e-5 weeks <br />7.9905e-6 months <br />, 8 minutes. Additionally, FitzPatrick staff identified three occasions when the maximum allowable service water temperature for the remaining four east CAVC subsystem unit coolers had been exceeded; however, none of these occasions exceeded the TRM AOT of seven days, and therefore did not constitute violations of regulatory requirements.

For the two periods when two unit coolers had been inoperable, the inspectors noted that the TRM AOT had been exceeded, but operability determinations had not been performed on ECCS subsystems in the east crescent area, specifically B RHR and B core spray subsystems, and the HPCI system. With no additional information provided in the LER, the inspectors concluded that these systems had to be considered inoperable after the seven day AOT had been exceeded. TS 3.5.1.H requires entry into TS LCO 3.0.3 in the case that two low pressure ECCS subsystems are inoperable.

Since both of the subject periods were longer than eight days, 13 hours1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br /> (that is, the seven day TRM AOT, plus the TS LCO completion time of 37 hours4.282407e-4 days <br />0.0103 hours <br />6.117725e-5 weeks <br />1.40785e-5 months <br />), both associated events constituted violations of TS LCO 3.0.3, and consequently, TS 3.5.1.

The inspectors discussed these conclusions with FitzPatrick staff, who responded by generating EC 53114, East Crescent Ventilation Functionality - 3 Unit Coolers in Service Summer 2010 and Summer 2011. This calculation utilized archived values of service water temperature and unit cooler thermal efficiency to evaluate the ability of the east CAVC subsystem to remove post-accident heat loads during the subject two periods. This evaluation concluded that, in both cases, there was reasonable assurance that the remaining three operable unit coolers would have been capable of removing required post-accident heat loads. The inspectors reviewed EC 53114 and determined that its conclusions were reasonable.

Analysis.

The inspectors determined that FitzPatrick staffs failure to promptly perform minimum pickup voltage testing for safety-related motor control center contactors after the need to do so was identified in 2005, such that the unsatisfactory performance of east CAVC unit cooler 66UC-22H was not identified until after it had resulted in two violations of TS 3.5.1, was a performance deficiency that was within FitzPatrick staffs ability to foresee and correct, and should have been prevented.

The finding was more than minor because it is associated with the Equipment Performance attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the unsatisfactory low voltage response of the 66UC-22H fan motor contactor, along with the unavailability of another east CAVC unit cooler due to maintenance, could have degraded the capability of ECCS systems in the east crescent area during an accident concurrent with degraded voltage conditions. In light of FitzPatrick staffs determination that there was reasonable assurance that the remaining three operable unit coolers would have been capable of removing required post-accident heat loads, the inspectors determined that the finding was of very low safety significance (Green) in accordance with IMC 0609.04, Initial Characterization of Findings, and Exhibit 2 of IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, because the performance deficiency was not a design or qualification deficiency, did not involve an actual loss of safety function, did not represent the actual loss of a safety function of a single train for greater than its TS AOT, and did not screen as potentially risk-significant due to a seismic, flooding, or severe weather initiating event.

This finding had a cross-cutting aspect in the area of Problem Identification and Resolution, Resolution, because FitzPatrick staff did not take effective corrective actions to address the low voltage pickup issue in a timely manner commensurate with its safety significance [P.3].

Enforcement.

TRM Section 3.7.C requires that an operability determination must immediately be performed for the affected ECCS subsystems and the RCIC system if a CAVC subsystem is inoperable for greater than seven days. TS 3.5.1.H requires entry into TS LCO 3.0.3 in the case that two low pressure ECCS subsystems are inoperable.

TS LCO 3.0.3 requires that, within one hour, action be initiated to place the plant in Mode 2 within 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br />, Mode 3 within 13 hours1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br />, and Mode 4 within 37 hours4.282407e-4 days <br />0.0103 hours <br />6.117725e-5 weeks <br />1.40785e-5 months <br />. Contrary to the above, with the plant operating in Mode 1 from 0300 on May 5, 2010, through 0800 on May 21, 2010, and from 1027 on March 15, 2011, through 0735 on March 25, 2011, the east CAVC subsystem had been inoperable and an operability determination was not immediately performed after seven days for the B RHR and the B core spray subsystems, and the HPCI system. As a result, these systems became inoperable, which required entry into TS LCO 3.0.3. In both cases, contrary to TS LCO 3.0.3, within one hour, action was not initiated to place the plant in Mode 2 within 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br />, Mode 3 within 13 hours1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br />, and Mode 4 within 37 hours4.282407e-4 days <br />0.0103 hours <br />6.117725e-5 weeks <br />1.40785e-5 months <br />. Because this violation was of very low safety significance (Green), and FitzPatrick staff entered this issue into their CAP as CR-JAF-2012-00584 and CR-JAF-2012-02288, this violation is being treated as an NCV, consistent with Section 2.3.2 of the Enforcement Policy. (NCV 05000333/2014005-02, TS Actions for Inoperable ECCS Not Performed Within the TS Allowed Completion Time) This LER is closed.

.2 (Closed) LER 05000333/2013-002-00: RCIC Condensate Storage Tank Level Switch

Inoperable due to Corrosion On August 19, 2013, both of the RCIC water level switches for the B CST, 13LS-76B and 13LS-77B, failed to trip during functional testing due to corrosion buildup on the level switches caused by water intrusion. 13LS-76B also failed to trip during previous quarterly testing on July 16, 2013, due to corrosion buildup. The corrosion was caused by water leakage through a junction box common to both B CST limit switches. As a result, both of the RCIC level switches for the B CST were inoperable from July 13, 2013 until August 19, 2013, and FitzPatrick did not place the channels in trip or declare RCIC inoperable in accordance with TS. The enforcement aspects of this issue are discussed in Section 4OA7. The inspectors did not identify any new issues during the review of this LER. This LER is closed.

4OA5 Other Activities

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

a. Inspection Scope

The inspectors reviewed the final report for the World Association of Nuclear Operators (WANO)/INPO plant assessment of FitzPatrick conducted in February and March 2014.

The inspectors reviewed this report to ensure that any issues identified were consistent with NRC perspectives of Entergys performance and to determine if WANO/INPO identified any significant safety issues that required further NRC follow-up.

b. Findings

No findings were identified.

.2 Closure of NRC Supplemental Inspection Report 05000333/2014007

In January 2014, inspectors conducted an inspection to evaluate FitzPatrick staffs response to the White performance indicator for unplanned power changes that originated in March 2013. The inspectors examined FitzPatrick staffs problem identification, root cause evaluation, extent of condition, extent of cause, and corrective actions for the root and contributing causes of this issue using IP 95001, Inspection for One or Two White Inputs in a Strategic Performance Area. The inspectors determined that all attributes of the inspection had been satisfactorily addressed except that the interim actions to reduce the number of unplanned power changes had been ineffective.

The inspectors concluded that the inspection would remain open until corrective actions to significantly reduce the unplanned power changes were implemented. These results were documented in NRC Supplemental Inspection Report 05000333/2014007 dated May 12, 2014.

During the refueling outage that was completed during this inspection period, FitzPatrick completed a full retubing of the main condenser. Completion of this action eliminated the need for interim corrective actions, in that retubing was the final corrective action to eliminate the problem. As of the close of this inspection period, there have been no main condenser tube leaks since startup from the refueling outage (a period of nearly three months). The inspectors concluded that all inspection attributes of IP 95001 had been completed, and no findings were identified. Therefore, the supplemental inspection of FitzPatrick staffs actions to address the White performance indicator for unplanned power changes is closed.

4OA6 Meetings, Including Exit

.1 Exit Meeting

On January 29, 2015, the inspectors presented the inspection results to Mr. Brian Sullivan, Site Vice President, and other members of the FitzPatrick staff. The inspectors verified that no proprietary information was retained by the inspectors or documented in this report.

.2 Regulatory Performance Meeting

As specified in IMC 0305, Operating Reactor Assessment Program, a Regulatory Performance meeting was conducted on January 29, 2015, between Mr. Arthur Burritt, Chief, Reactor Projects Branch 2, and members of the FitzPatrick staff to discuss results of the completed IP 95001 for the White performance indicator for unplanned power changes as documented in NRC Supplemental Inspection Report 05000333/2014007 and Section 4OA5.2 of this report. The NRC discussed the identified performance deficiencies and the adequacy of Entergys completed corrective actions with the FitzPatrick staff.

4OA7 Licensee-Identified Violations

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

TS 3.3.5.2, Reactor Core Isolation Cooling (RCIC) System Instrumentation, requires that the RCIC system instrumentation for all 4 channels of low CST water level be operable while in Modes 1, 2, or 3 with reactor steam dome pressure greater than 150 psig. With any level switch inoperable, Condition D requires that the channel be placed in trip. When this condition is not met, Condition E requires that RCIC be declared inoperable. LCO 3.5.3, RCIC System, further requires that RCIC be restored to operable status within 14 days or be placed in Mode 3. Contrary to TS 3.3.5.2, with two RCIC CST level switches, 13LS-76B and -77B, inoperable from July 16, 2013 to August 19, 2013, Entergy did not place the channels in trip or declare RCIC inoperable, or place the reactor in Mode 3 per TS 3.5.3. The cause of the inoperability was corrosion buildup on the level switches caused by water intrusion through a junction box common to the switches. Entergy entered this issue into the CAP as CR-JAF-2013-04311. The inspectors determined, through a review of IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings at Power, Exhibit 2, that the finding was of very low safety significance (Green) because the finding was not related to a design or qualification deficiency, did not represent a loss of a mitigating system safety function, and did not screen as potentially risk significant due to external initiating events. The Senior Reactor Analyst (SRA) used the Systems Analysis Programs for Hands-On Evaluation (SAPHIRE), Revision 8.1.2, and the Standardized Plant Analysis Risk (SPAR) Model for Fitzpatrick, Model Version 8.1.17, to confirm that no loss of safety function occurred. The SRA determined that the RCIC pump suction is assumed to remain on the CST for the duration of operation to complete its safety function and therefore this issue was determined to be of very low safety significance (Green). The CST inventory is modeled to be sufficient because the function of RCIC is to respond to transient events to provide makeup coolant to the reactor.

ATTACHMENT:

SUPPLEMENTARY INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

L. Coyle, Site Vice President

C. Adner, Manager, Licensing

B. Finn, Director, Nuclear Safety Assurance

K. Irving, Manager, Programs and Components Engineering

S. McAllister, Director, Engineering

D. Poulin, Manager, Operations

T. Redfearn, Manager, Security

M. Reno, Manager, Maintenance

B. Sullivan, General Manager, Plant Operations

R. Brown, Manager, Radiation Protection

LIST OF ITEMS OPENED, CLOSED, DISCUSSED, AND UPDATED

Open/Closed

05000333/2014005-01 NCV Untimely 10 CFR 50.72 Notification of a Secondary Containment System Functional Failure (Section 1R15)

05000333/2014005-02 NCV TS Actions for Inoperable ECCS Not Performed Within the TS Allowed Completion Time (Section 4OA3)

Closed

05000333/2012-001-00, 01 LER Unit Cooler Fan Motor Contactor Low Voltage Test Failure Results in Loss of Safety Function and Condition Prohibited by the Technical Specifications (Section 4OA3)

05000333/2013-002-00 LER RCIC Condensate Storage Tank Level Switch Inoperable due to Corrosion (Section 4OA3)