IR 05000333/2013004
| ML13316C427 | |
| Person / Time | |
|---|---|
| Site: | FitzPatrick  |
| Issue date: | 11/06/2013 |
| From: | Arthur Burritt Reactor Projects Branch 2 |
| To: | Coyle L Entergy Nuclear Northeast |
| Burritt A | |
| References | |
| IR-13-004 | |
| Download: ML13316C427 (28) | |
Text
UNITED STATES mber 6, 2013
SUBJECT:
JAMES A. FITZPATRICK NUCLEAR POWER PLANT - NRC INTEGRATED INSPECTION REPORT 05000333/2013004
Dear Mr. Coyle:
On September 30, 2013, 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 October 21, 2013, 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.
The report documents one self-revealing finding of very low safety significance (Green). This finding was determined to involve a violation of NRC requirements. However, because of its very low safety significance, and because it is entered into your corrective action program, the NRC is treating this finding as a non-cited violation (NCV), consistent with Section 2.3.2 of the NRC Enforcement Policy. If you contest the NCV 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 20555-001; with copies to the Regional Administrator, Region I; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-001; 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 Senior Resident Inspector at FitzPatrick.
In accordance with Title 10 of the Code of Federal Regulations 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 NRC Public Document Room or from the Publicly Available Records (PARS) component of the NRCs Agencywide Documents Access and Management System (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
Sincerely,
/RA/
Arthur L. Burritt, Chief Reactor Projects Branch 2 Division of Reactor Projects Docket No. 50-333 License No. DPR-59
Enclosure:
Inspection Report No. 05000333/2013004 w/Attachment: Supplementary Information
REGION I==
Docket No.: 50-333 License No.: DPR-59 Report No.: 05000333/2013004 Licensee: Entergy Nuclear Northeast (Entergy)
Facility: James A. FitzPatrick Nuclear Power Plant Location: Scriba, NY Dates: July 1, 2013 through September 30, 2013 Inspectors: E. Knutson, Senior Resident Inspector B. Sienel, Resident Inspector T. Burns, Reactor Inspector J. Laughlin, Emergency Preparedness Inspector M. Patel, Reactor Inspector Approved by: Arthur L. Burritt, Chief Reactor Projects Branch 2 Division of Reactor Projects Enclosure
SUMMARY
IR 05000333/2013002; 07/01/2013 - 09/30/2013; James A. FitzPatrick Nuclear Power Plant (FitzPatrick); Plant Modifications.
This report covered a three-month period of inspection by resident inspectors, announced inspections performed by regional inspectors, and an in-office review conducted by a headquarters-based inspector. One self-revealing finding of very low safety significance (Green) was identified, which was a non-cited violation (NCV) of NRC requirements. 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, Components Within the Cross-Cutting Areas, dated October 28, 2011. All violations of NRC requirements are dispositioned in accordance with the NRCs Enforcement Policy, dated January 28, 2013. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process,
Revision 4.
Cornerstone: Initiating Events
- Green.
The inspectors identified a Green self-revealing NCV of Technical Specification (TS)5.4, Procedures, because Entergy staff did not adequately preplan the implementation of a plant modification to install a digital reactor water recirculation (RWR) flow control system during the 2012 refueling outage. Specifically, post-maintenance testing (PMT) failed to identify that a portion of the runback logic was incorrectly programmed. As a result, the RWR system was restored to operation without identifying the error. On November 8, 2012, during power ascension activities following a subsequent forced outage, the A RWR pump demand signal increased from minimum flow (approximately 30 percent) to approximately 44 percent with no operator action when feedwater flow increased above 20 percent. This resulted in an unexpected power increase of approximately 1.4 percent (37 megawatts thermal (MWth)). As immediate corrective action, control room operators reduced flow in the A RWR loop to restore it to pre-transient conditions, locked the scoop tubes for both RWR motor-generators, and placed the power ascension on hold pending further evaluation of the event. The issue was entered into the corrective action program (CAP) as condition report (CR)-JAF-2012-08042. The issue of inadequate PMT was subsequently entered into the CAP as CR-JAF-2013-05326.
The finding was more than minor because it was similar to Example 4.b in IMC 0612,
Appendix E, Examples of Minor Issues, in that it resulted in a plant transient. In addition, the finding adversely affected the Initiating Events cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. In accordance with IMC 0609.04, Initial Characterization of Findings, and Exhibit 1 of IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, issued June 19, 2012, the inspectors determined this finding was of very low significance (Green) because the performance deficiency did not cause a reactor trip or the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition. The finding had a cross-cutting aspect in the area of Human Performance, Resources, because FitzPatrick did not ensure that the PMT acceptance criteria specified in the engineering change (EC)package were clearly translated into PMT testing work packages to verify successful implementation of the digital RWR flow control modification H.2(c). (Section 1R18)
REPORT DETAILS
Summary of Plant Status
James A. FitzPatrick Nuclear Power Plant (FitzPatrick) began the inspection period at 100 percent power. On July 18, 2013, operators reduced power to 50 percent to address main condenser tube leakage. Following identification and repair, operators restored power to 100 percent the following day. On August 23, 2013, operators reduced power to 50 percent to address main condenser tube leakage. Following identification and repair, operators were increasing power when, at 96 percent on August 24, 2013, the B reactor feedwater pump (RFP) began to exhibit high vibrations. Operators reduced power to 90 percent and B RFP vibrations returned to acceptable (although still elevated) levels. On September 6, 2013, operators reduced power to 55 percent and secured the B RFP to address the vibration issue.
On September 12, 2013, operators further reduced power to 50 percent to address main condenser tube leakage. Following repair of these issues, operators restored power to 100 percent on September 13, 2013. On September 14, 2013, operators reduced power to 72 percent to perform a control rod pattern adjustment and restored power to 100 percent later that day. The plant 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
Readiness for Impending Adverse Weather Conditions
a. Inspection Scope
On August 13, 2013, 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.
Documents reviewed for each section of this inspection report are listed in the
.
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:
High pressure coolant injection (HPCI) system while the reactor core isolation cooling (RCIC) system was inoperable for planned maintenance on July 16, 2013 B control room emergency ventilation air supply (CREVAS) system while A CREVAS system was inoperable for planned maintenance on July 18, 2013 A standby liquid control (SLC) system while B SLC was inoperable for planned maintenance on July 31, 2013 A core spray system while B core spray system was inoperable for planned maintenance on August 1, 2013 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 Updated Final Safety Analysis Report (UFSAR), technical specifications (TSs), condition reports (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 August 6, 2013, the inspectors performed a complete system walkdown of accessible portions of the standby gas treatment 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, hangar and support functionality, and operability of support systems. The inspectors performed field walkdowns of accessible portions of the systems 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 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.
North and south safety-related pump rooms, fire area/zone XIII/SP-2, on July 30, 2013 Reactor building east crescent area, fire area/zone XVII/RB-1E, on August 2, 2013 Reactor building 344 foot elevation, fire area/zone IX/RB-1A, on August 6, 2013 Reactor building 326 foot elevation, fire area/zone IX/RB-1A, on August 15, 2013 Main control room, administration building 300 foot elevation, fire area/zone VII/CR-1, on August 20, 2013
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 north and south cable tunnels to verify the adequacy of floor and water penetration seals and common drain lines and sumps.
b. Findings
No findings were identified.
.2 Annual Review of Cables Located in Underground Bunkers/Manholes (3 samples)
a. Inspection Scope
The inspectors examined manholes MH-6A, MH-6B, and MH-8A in the 345 kilovolt (kV)switchyard during FitzPatrick staffs annual inspection of manhole sump pumps under work order (WO) 52463551. These manholes contain non-safety class electrical cables that could affect the reliability of the 345 kV system. The inspectors verified that cable insulation was not visibly degraded. The inspectors observed that many of the cable trays and supports were significantly 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 history of such failures. FitzPatrick structural engineering staff determined that, although degraded, the trays and supports were still capable of supporting the cables. Entergy staff initiated two CRs to identify the extent of these conditions and develop corrective actions. 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.
1R07 Heat Sink Performance
a. Inspection Scope
The inspectors reviewed the A emergency diesel generator (EDG) jacket water heat exchanger performance to determine its readiness and availability to perform its safety functions. This heat exchanger is cooled by the emergency service water (ESW)system. The inspectors reviewed the design basis for the component and verified Entergys commitments to NRC Generic Letter 89-13, Service Water System Problems Affecting Safety-Related Equipment. The inspectors reviewed and discussed the results of the September 2013 inspection and eddy current testing with engineering staff and reviewed pictures of the as-found and as-left conditions. The inspectors verified that Entergy staff initiated appropriate corrective actions for identified deficiencies. The inspectors also verified that the number of tubes plugged within the heat exchanger did not exceed the maximum amount allowed.
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 July 29, 2013, which included an invalid HPCI initiation, loss of service water, and a low power anticipated transient without scram. 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 August 23, 2013, the inspectors observed control room operator response to high conductivity in the condensate system caused by a leaking condenser tube. Operator response included reducing power to 50 percent using control rods and recirculation flow. 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 Title 10 of the Code of Federal Regulations (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.
4160 volt alternating current distribution EDG ventilation
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:
Planned RCIC and B CREVAS maintenance and emergent maintenance to address main condenser tube leakage that required power to be reduced to 50 percent during the week of July 15, 2013 B residual heat removal (RHR) quarterly surveillance test, B and D EDG monthly surveillance test, and one day maintenance periods for the B SLC and B core spray systems during the week of July 29, 2013 Emergent maintenance on RCIC instrumentation as well as emergent maintenance to address main condenser tube leakage that required power to be reduced to 50 percent during the week of August 19, 2013 Planned A EDG system and B RFP maintenance which required power to be reduced to 50 percent during the week of September 9, 2013 A SLC system quarterly surveillance test and emergent maintenance to replace the RCIC system condensate storage tank (CST) low level automatic suction swapover detector during the week of September 16, 2013
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-2013-03498 concerning the effect of a step decrease in a local power range monitor output on operability of its associated average power range monitor (APRM)on July 3, 2013 CR-JAF-2013-04246 concerning the operability of control rod 06-15 while its hydraulic control unit accumulator was inoperable due to nitrogen leakage, given the additional control rod operational restrictions that may be imposed due to the cores susceptibility to fuel channel - control blade interference on August 15, 2013 CR-JAF-2013-04311 concerning the operability of a RCIC CST low water level switch following a surveillance failure on August 19, 2013 CR-JAF-2013-03721 concerning the operability of reserve station service transformers 71T-2 and 71-T3 while the cooling fan breaker overloads were incorrectly set low such that the transformers would only have natural circulation cooling during periods of high outside temperatures on August 26, 2013 CR-JAF-2013-04668 concerning the positioning of a large portion of the spare normal service water pump casing in the screenwell; specifically, whether it would fall over and break through the floor in a seismic event, given that the floor is also the ceiling for the B safety-related pump room on September 11, 2013 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
No findings were identified.
1R18 Plant Modifications
.1 Permanent Modification - Seismic Monitoring System
a. Inspection Scope
The inspectors evaluated a modification to the seismic monitoring system being implemented by EC 37682, Replace Seismic Monitoring System. Performance of the existing seismic monitoring system has been challenged by equipment obsolescence, and recent industry operating experience has also indicated the value of system upgrades. The new digital system will provide more timely processing and evaluation of data, and will continue to function during a station blackout. 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 upgrade and design change, and reviewed the 10 CFR 50.59 screening.
b. Findings
No findings were identified.
.2 Permanent Modification - Reactor Water Recirculation Flow Control System
a. Inspection Scope
The inspectors evaluated a modification to the RWR flow control system implemented by EC 26765, Install Digital RWR Recirc Flow Control System. This modification replaced the original analog RWR flow control instrumentation and controls with digital equipment, mainly to address obsolescence issues with the analog equipment. 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. The inspectors also reviewed portions of the PMT that was performed following the installation of the modification and discussed the modification with operators and engineering personnel.
b. Findings
Introduction.
The inspectors identified a Green self-revealing NCV of TS 5.4, Procedures, because Entergy staff did not adequately perform PMT following the implementation of a plant modification to install a digital RWR flow control system during the 2012 refueling outage. Specifically, PMT failed to identify that a portion of the runback logic was incorrectly programmed.
Description.
EC 25665 was developed to install a digital RWR flow control system during the 2012 refueling outage. The modification was installed during the outage and the specified PMT was completed satisfactorily in October 2012.
On November 8, 2012, with the reactor at approximately 23 percent power during power ascension activities following an unplanned scram on November 4, the A RWR pump speed increased by approximately 10 percent with no operator action. The resultant RWR flow increase caused reactor power to increase by approximately 37 MWth) or 1.4 percent rated power). Control room operators entered abnormal operating procedure AOP-32, Unplanned Power Change. As immediate corrective action, control room operators reduced flow in the A RWR loop to the pre-transient setting, locked the scoop tubes for both RWR motor-generators, and placed the power ascension on hold pending further evaluation of the event. The issue was entered into the CAP as CR-JAF-2012-
===08042.
The RWR control logic is designed with two RWR pump speed limiters. The #1 speed limiter reduces recirculation flow to minimum (approximately 30 percent) when certain plant conditions are met. One of these conditions is feedwater flow is less than 20 percent. The #2 limiter reduces recirculation flow to approximately 44 percent under certain conditions. During a reactor scram on November 4, 2012, plant conditions were such that first the #2 limiter was activated followed by the #1 limiter for both RWR pumps, as designed. During the forced outage that followed, work was performed on both RWR pump field breakers. During restoration from the work, the B RWR pump was returned to service using operating procedure OP-27, Recirculation System. This procedure directed operators to manually set pump speed to minimum as part of the pump startup. The A RWR pump was restored to service using surveillance test ST-27C, Recirc Loop Valve Operability Test with RWR In Service and All Rods In, which does not include direction to set pump speed to minimum.
Entergy staff determined the unplanned A RWR loop flow increase occurred when feedwater flow went above 20 percent during the power ascension. This cleared the #1 limiter which had been in effect on both RWR pumps, as designed. The intent of the digital modification design was to drop the internal controller setpoint to minimum when the #1 limiter was received during the reactor scram. However, due to an error in the programmed logic, this did not occur. The internal controller setpoint remained at the 44 percent limiter setting due to this error, so when the 30 percent limiter cleared, A RWR pump speed increased to 44 percent with no operator action.
The inspectors interviewed engineering personnel and reviewed the EC documentation.
The inspectors noted that the post modification test plan (PMTP) portion of the EC, which specifies the testing required to be done as part of the modification, recognized the need to test the interaction of the two speed limiters. Construction (bench) testing as well as return to service functional testing were specified in the PMTP to verify proper operation of the internal controller setpoint when both limiters were received. While both the construction testing WO 27693901 and PMT WO 27694304 make reference to this portion of the PMTP, the inspector determined the procedures were not clear enough to communicate to test personnel which controller parameters were to be verified.
Although both WOs were signed off as completed satisfactorily, it is clear based on the power increase that occurred on November 8, 2012, that the testing had not been performed as intended in the PMTP. This aspect of the issues associated with the digital RWR flow control system modification was entered into the CAP as CR-JAF-2013-05326.
Analysis.
The inspectors determined that the failure to provide adequate PMT procedures for the digital RWR flow control modification in accordance with TS 5.4, Procedures, was a performance deficiency that was within Entergy staffs ability to foresee and correct and should have been prevented. Specifically, the RWR system provides one of the primary means of changing reactor reactivity, and development of clear PMT requirements was reasonably within the ability of Design Engineering personnel. This finding was more than minor because it was similar to Example 4.b in IMC 0612, Appendix E, Examples of Minor Issues, in that it resulted in a plant transient.
In addition, the finding affected the Initiating Events cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations.
In accordance with IMC 0609.04, Initial Characterization of Findings, and Exhibit 1 of IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, issued June 19, 2012, the inspectors determined this finding was of very low significance (Green) because the performance deficiency did not cause a reactor trip or the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition.
The finding had a cross-cutting aspect in the area of Human Performance, Resources, because FitzPatrick staff did not ensure that accurate work packages were available to assure successful implementation of the digital RWR flow control modification H.2(c).
Enforcement.
TS 5.4, Procedures, states, in part, Written procedures shall be established, implemented, and maintained coveringthe applicable procedures recommended in Regulatory Guide (RG) 1.33, Appendix A, November 1972. RG 1.33, Appendix A, November 1972,Section I, Procedures for Performing Maintenance, states, in part, Maintenance which can affect the performance of safety-related equipment should be properly preplanned and performed in accordance with written procedures, documented instructions, or drawings appropriate to the circumstances.
RG 1.33, Appendix A, November 1972, Section D, Procedures for Startup, Operation, and Shutdown of Safety Related BWR [boiling water reactor] Systems, includes the nuclear steam supply system recirculating system as such a system.
Contrary to the above, installation of digital recirculation flow controllers maintenance which could affect the performance of the RWR system, was not properly preplanned and performed in accordance with written procedures and documented instructions appropriate to the circumstances. Specifically, the PMT step to verify the internal setpoint did not clearly articulate where the setpoint should be read. In addition, the verification of the setpoint and the demand signal were combined in the same step, further complicating the direction. Because this issue was of very low safety significance (Green) and Entergy entered this issue into their CAP as CR-JAF-2013-05326, this finding is being treated as an NCV, consistent with the NRC Enforcement Policy. (NCV 05000333/2013004-01, Inadequate Reactor Water Recirculation Digital Flow Control Modification Post Maintenance Test Procedure Results in Unexpected Power Increase)
1R19 Post-Maintenance Testing
a. Inspection Scope
The inspectors reviewed the post-maintenance tests 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 52366838 to replace the control room exhaust fan 70FN-4A start logic relay on July 23, 2013 WO 52210243-01 to replace positive/negative 20 volts direct current instrument power supply 07P/S-14 for F APRM and B flow unit on August 1, 2013 WO 00341970 to calibrate the HPCI turbine lube oil filter differential pressure switch, 23DPS-1 on August 5, 2013 WO 00264943-01 to replace each fuse block for the A side containment air dilution monitoring analysis panel on August 13, 2013 Started B RFP as PMT for various work orders performed to identify and correct the cause of excessive vibrations when operating near 100 percent, in accordance with OP-2A, Feedwater System, with additional vibration monitoring on September 12, 2013 WO 52507988 to perform ST-9BA, EDG A and C Full Load Test and ESW Pump Operability Test, to support PMT for numerous maintenance activities performed during the preceding five day maintenance period on September 13, 2013 WO 00357076 to replace RCIC CST level switch 13LS-76B, on September 18, 2013
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:
ISP-125A, HPCI Auto Isolation Instrument Functional Test/Calibration (ATTS)
[analog transmitter trip system], on July 30, 2013 ST-8E, ESW Logic System Functional Test and Simulated Automatic Actuation Test, on August 7, 2013 ISP-71A, Intermediate Range Monitor Division A Instrument Trip Functional Calibration, on August 13, 2013 ISP-100A-PCIS, PCIS [primary containment isolation system] Instrument Functional/Calibration (ATTS), on August 20, 2013 ST-2AM, RHR Loop B Quarterly Operability Test (IST) [in-service test], on August 28, 2013 ST-3JB, Core Spray Initiation Logic System B Functional Test, on September 25, 2013
b. Findings
No findings were identified.
Cornerstone: Emergency Preparedness
1EP4 Emergency Action Level and Emergency Plan Changes
a. Inspection Scope
The headquarters staff performed an in-office review of the latest revisions of various Emergency Plan Implementing Procedures and the Emergency Plan located under ADAMS accession numbers ML13179A490 and ML13225A232 as listed in the
.
The licensee determined that in accordance with 10 CFR 50.54(q), the changes made in the revisions resulted in no reduction in the effectiveness of the Plan, and that the revised Plan continued to meet the requirements of 10 CFR 50.47(b) and Appendix E to 10 CFR Part 50. The NRC review was not documented in a safety evaluation report and did not constitute approval of licensee-generated changes; therefore, this revision is subject to future inspection.
b. Findings
No findings were identified.
OTHER ACTIVITIES
4OA1 Performance Indicator Verification
Unplanned Scrams and Unplanned Scrams with Complications
a. Inspection Scope
The inspectors reviewed Entergys submittals for the following Initiating Events cornerstone performance indicators for the period July 1, 2012 through June 30, 2013:
Unplanned Scrams Unplanned Scrams with Complications To determine the accuracy of the performance indicator data reported during this period, inspectors used definitions and guidance contained in Nuclear Energy Institute Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, and NUREG-1022, Event Reporting Guidelines 10 CFR 50.72 and 10 CFR 50.73."
The inspectors reviewed licensee event reports and NRC integrated inspection reports to validate the accuracy of the submittals.
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 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 Annual Sample: 71T-1A Main Transformer Failure
a. Inspection Scope
The inspectors performed an in-depth review of Entergy staffs root cause analysis and corrective actions associated with CR-JAF-2012-08084 concerning failure of the 71T-1A, main transformer. Specifically, while operating at 100 percent power on November 11, 2012, a main turbine trip occurred which caused an automatic reactor scram. All systems responded as expected and operators stabilized plant conditions. Operators determined that the turbine trip was in response to a fire in one of two main transformers. On-site fire brigade personnel responded to combat the fire and assistance was requested from a local fire department.
The inspectors assessed Entergy staffs problem identification threshold, cause analyses, extent-of-condition reviews, compensatory actions, and the prioritization and timeliness of Entergy staffs corrective actions to determine whether Entergy staff was appropriately identifying, characterizing, and correcting problems associated with the main transformer failure and whether the planned or completed corrective actions were appropriate. The inspectors compared the actions taken to the requirements of Entergys CAP.
b. Findings and Observations
No findings were identified.
The inspectors determined that Entergy staff appropriately identified, characterized, and implemented corrective actions associated with the main transformer failure. However, inspectors noted that further information from an extensive forensic investigation and failure analysis was still pending, therefore, a comprehensive root causes was not finalized. The inspector reviewed the possible root causes and their associated corrective actions and determined them to be adequate. The inspectors noted that, as a result of extent of condition review, Entergy staff increased monitoring and trending on main transformer 71T-1B and identified a degrading trend in the 71T-1B oil analysis. On June 15, 2013, Entergy reduced power and went off-line to remove 71T-1B from service to investigate the cause of the increase in dissolved gases (acetylene and hydrogen)from the oil analyses. Internal inspection on 71T-1B identified a degraded bolt connection on the de-energized tap changer. Entergy staff corrected and repaired the degraded condition.
The inspector determined Entergy staffs overall response to the issue was commensurate with its safety significance, was timely, and the actions taken and planned were reasonable to resolve the main transformer failure issue.
4OA3 Follow-Up of Events and Notices of Enforcement Discretion
.1 (Closed) Licensee Event Report (LER) 05000333/2012-010-00: High Pressure Coolant
Injection System Inoperable On June 6, 2012, while the HPCI system was inoperable for planned maintenance, testing of the HPCI suppression pool suction isolation valve, 23MOV-57, identified that the valve did not fully open on demand. The cause was determined to be high resistance on the open torque switch due to corrosion on the switch contacts. As corrective action, the contacts were cleaned and the valve was tested and determined to be operating properly.
Entergy personnel identified that failure of 23MOV-57 to fully open during an automatic transfer of HPCI pump suction from the CSTs to the suppression pool would have prevented the CST isolation valve from automatically closing. This condition had the potential to create a drain down condition in the CSTs that could entrain air into the HPCI pump suction and cause a loss of HPCI. Entergy personnel considered that HPCI could nonetheless be considered operable while the 23MOV-57 failure existed, because operator action could be credited to realign the suction isolation valves such that air entrainment would be avoided. However, the inspectors determined that credit for operator action was inappropriate because the applicable procedure did not contain an adequate level of detail to provide virtual certainty of success during accident conditions, and therefore that the issue required submittal of an LER.
The inspectors reviewed this issue as documented in NRC Integrated Inspection Report 05000333/2013002. The inspectors did not identify any new issues during the review of the LER. This LER is closed.
.2 (Closed) LER 05000333/2013-001-00: Failed Under Voltage Relay Results in Auto Start
of the Emergency Diesel Generators On January 15, 2013, with the plant operating at 100 percent power, Entergy staff were performing surveillance test ST-43D, Remote Shutdown Panel 25ASP-3 Component Operation and Isolation Verification, when the B and D EDGs unexpectedly started and the associated 10600 vital bus de-energized. This resulted in a reactor protection system B half scram and automatic closure of Group II containment isolation valves.
The EDG output breaker closure circuitry had been previously disabled as a part of ST-43D, so the 10600 bus was not promptly reenergized. Consequently, the B ESW pump did not start to provide cooling, and the EDGs subsequently shut down automatically due to high jacket water temperature.
Entergy staff determined the cause of this event to have been a failed under voltage relay for the 10600 bus. The relay had failed in a manner that satisfied half of the circuit logic that is used to detect a loss of voltage on the 10600 bus and initiate an automatic start of the EDGs. When a step in ST-43D satisfied the remaining half logic, the B and D EDGs started and the normal supply circuit breakers to the 10600 bus automatically opened. The inspectors reviewed this LER and identified no findings or violations of regulatory requirements. This LER is closed.
4OA5 Other Activities
.1 Temporary Instruction 2515/182, Review of the Industry Initiative to Control Degradation
of Underground Piping and Tanks, Phase 2 ===
a. Inspection Scope
The licensees buried piping and underground piping and tanks program was inspected in accordance with paragraph 03.02.a of Temporary Instruction (TI) 2515/182. It was confirmed that activities which correspond to the completion dates, specified in the program, which have passed since the Phase 1 inspection was conducted, have been completed.
The licensees buried piping and underground piping and tanks program was inspected in accordance with paragraph 03.02.b of the TI and responses to specific questions found in www.nrc.gov/reactors/operating/ops-experience/buried-pipe-ti-phase-2-insp-req-2011-11-16.pdf were submitted to NRC headquarters staff.
b. Findings
No findings were identified.
4OA6 Meetings, Including Exit
Exit Meeting On October 21, 2013, the inspectors presented the inspection results to Mr. Lawrence Coyle, 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.
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, Acting Manager, Radiation Protection
LIST OF ITEMS OPENED, CLOSED, DISCUSSED, AND UPDATED
Open/Closed
- 05000333/2013004-01 NCV Inadequate Reactor Water Recirculation Digital Flow Control Modification Post Maintenance Test Procedure Results in Unexpected Power Increase (Section 1R18)
Closed
- 05000333/2012-010-00 LER High Pressure Coolant Injection System Inoperable (Section 4OA3)
- 05000333/2013-001-00 LER Failed Under Voltage Relay Results In Auto Start of the Emergency Diesel Generators (Section 4OA3)