IR 05000333/2012002
| ML12115A040 | |
| Person / Time | |
|---|---|
| Site: | FitzPatrick  |
| Issue date: | 04/24/2012 |
| From: | Mel Gray Reactor Projects Branch 2 |
| To: | Michael Colomb Entergy Nuclear Northeast |
| References | |
| IR-12-002 | |
| Download: ML12115A040 (24) | |
Text
UNITED STATES ril 24, 2012
SUBJECT:
JAMES A. FITZPATRICK NUCLEAR POWER PLANT - NRC INTEGRATED INSPECTION REPORT 05000333/2012002
Dear Mr. Colomb:
On March 31, 2012, 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 April 23, 2012, 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 NRC-identified Severity Level IV non-cited violation (NCV). This finding was determined to involve a violation of NRC requirements. However, because of the very low safety significance, and because it is entered into your corrective action program, the NRC is treating this finding as an 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 the 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 Senior Resident Inspector at FitzPatrick.
In accordance with 10 CFR Part 2.390 of the NRC's "Rules of Practice," a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of the NRCs document 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/
Mel Gray, Chief Reactor Projects Branch 2 Division of Reactor Projects Docket No.: 50-333 License No.: DPR-59
Enclosure:
Inspection Report 05000333/2012002 w/Attachment: Supplementary Information
REGION I==
Docket No.: 50-333 License No.: DPR-59 Report No.: 05000333/2012002 Licensee: Entergy Nuclear Northeast (Entergy)
Facility: James A. FitzPatrick Nuclear Power Plant Location: Scriba, New York Dates: January 1 through March 31, 2012 Inspectors: E. Knutson, Senior Resident Inspector B. Sienel, Resident Inspector T. Burns, Reactor Inspector Approved by: Mel Gray, Chief Reactor Projects Branch 2 Division of Reactor Projects Enclosure
SUMMARY OF FINDINGS
IR 05000333/2012002; 01/01/2012 - 03/31/2012; James A. FitzPatrick Nuclear Power Plant (FitzPatrick); Follow-up of Events.
The report covered a three-month period of inspection by resident inspectors and an announced inspection performed by regional inspectors. Inspectors identified one Severity Level (SL) IV finding, which was a non-cited violation (NCV). The significance of most findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual Chapter (IMC) 0609,
Significance Determination Process (SDP). The cross-cutting aspects for the findings were determined using IMC 0310, Components Within Cross-Cutting Areas. Findings for which the SDP does not apply may be Green, or be assigned a severity level after NRC management review. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 4, dated December 2006.
Cornerstone: Mitigating Systems
- Severity Level IV. The inspectors identified a Severity Level (SL) IV non-cited violation (NCV) of 10 CFR Part 50.73, Licensee Event Report [LER] System, because a violation of Technical Specification (TS) 3.5.1.G for the condition of the high pressure coolant injection (HPCI) and reactor core isolation cooling (RCIC) systems being simultaneously inoperable was not reported to the NRC within 60 days of discovery. After this was identified by the inspectors, the issue was entered into Entergys corrective action program (CAP) as CR-JAF-2011-04779. Entergy subsequently submitted Revision 1 to LERs 05000333/2010-005-00 and 05000333/2011-001-00.
The inspectors determined that the failure to revise LER 05000333/2010-005-00 within 60 days to include the violation of TS 3.5.1.G in accordance with 10 CFR Part 50.73 was a performance deficiency that was reasonably within Entergys ability to foresee and correct, and should have been prevented. Because the issue impacted the regulatory process, in that a violation of site Technical Specifications was not reported to the NRC within the required timeframe, thereby delaying the NRCs opportunity to review the matter, the inspectors evaluated this performance deficiency in accordance with the traditional enforcement process. Using example 6.9.d.9 from the NRC Enforcement Policy, the inspectors determined 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 did not make a report required by 10 CFR Part 50.73. In accordance with Inspection Manual Chapter (IMC) 0612, Appendix B, traditional enforcement issues are not assigned cross-cutting aspects. (Section 4OA3)
REPORT DETAILS
Summary of Plant Status
The James A. FitzPatrick Nuclear Power Plant (FitzPatrick) began the inspection period at 100 percent power. On January 15, 2012, operators reduced power to 50 percent to identify and plug leaking main condenser tubes. Operators returned the unit to 100 percent power the following day. On January 17, operators reduced power to 65 percent due to loss of flow from the C condensate booster pump (CBP). Operators increased power to 81 percent later that day, based on reaching the electric current limit for the remaining two CBPs, and to 93 percent on January 21, based on a revised CBP motor current limit. After repairs to the C CBP were completed, operators reduced power to 75 percent to return the pump to service, then returned the unit to 100 percent power on January 23. On January 25, operators reduced power to 50 percent to identify and plug leaking main condenser tubes. Operators returned the unit to 100 percent power on January 27. On January 28, operators reduced power to 65 percent for a control rod pattern adjustment and returned the unit to 100 percent power later that day. On March 29, operators reduced power to 65 percent for a control rod sequence exchange, single control rod scram time testing, control rod blade interference testing, and turbine valve testing.
Operators returned the unit to 100 percent power later that day, and remained at 100 percent power for the remainder of the inspection period.
REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity
1R04 Equipment Alignment
.1 Partial System Walkdowns
a. Inspection Scope
The inspectors performed partial walkdowns of the following systems:
- 'A' and 'C' emergency diesel generators (EDGs) during 'D' EDG maintenance on January 19, 2012
- B standby liquid control (SLC) system during A SLC system maintenance on February 9, 2012
- B residual heat removal (RHR) system during A RHR system maintenance on February 28, 2012 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), TSs, and 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 corrective action program (CAP) for resolution with the appropriate significance characterization. Documents reviewed for each section of this inspection report are listed in the Attachment.
b. Findings
No findings were identified.
.2 Full System Walkdown
a. Inspection Scope
During the week of March 5, the inspectors performed a complete system walkdown of accessible portions of the A RHR system to verify the existing equipment lineup was correct. The inspectors reviewed operating procedures, surveillance tests, 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 reports to ensure Entergy staff appropriately evaluated and resolved any deficiencies.
b. Findings
No findings were identified.
1R05 Fire Protection
.1 Resident Inspector Quarterly Walkdowns
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 personnel 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.
- Reactor building fire area/zone IX/RB-1A and X/RB-1B, on February 10, 2012
- East cable tunnel, fire area/zone II/CT-2, on February 13, 2012
- Relay room, fire area/zone VII/RR-1, on February 15, 2012
- East switchgear room, fire area/zone II/SW-2, on February 17, 2012
- Reactor building west crescent, fire area/zone XVIII/RB-1W, on March 8, 2012
b. Findings
No findings were identified.
1R06 Flood Protection Measures
.1 Internal Flooding Review
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.
1R11 Licensed Operator Requalification Program
.1 Quarterly Review of Licensed Operator Requalification Testing and Training
a. Inspection Scope
The inspectors observed licensed operator simulator training on January 30, which included failure of a reactor pressure transmitter, failure of a circulating water pump, and a reactor coolant leak in the drywell that led to a manual reactor scram with failure of all control rods to fully insert. 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. The inspectors verified the accuracy and timeliness of the emergency classification made by the shift manager and the technical specification action statements entered by the shift technical advisor. 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 January 17, the inspectors observed control room operators during an unplanned power reduction from 100 percent to 65 percent due to failure of the C condensate booster pump, and subsequent operations to close the pump discharge isolation valve and secure the pump. The inspectors also observed control room operators during restoration of the pump to service on January 23. 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. As applicable, 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
- Reactor water recirculation flow control
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 Title 10, Code of Federal Regulations (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:
- Troubleshooting of an electrical ground in generator voltage regulator rectifier bank 2 involving the station 125 volt direct current (VDC) electrical system during the week of January 9, 2012
- Planned maintenance on D EDG and emergent maintenance on the C condensate booster pump during the week of January 16, 2012
- Planned maintenance on the reactor core isolation cooling (RCIC) system during the week of January 30, 2012
- Planned maintenance on A SLC system during the week of February 6, 2012
- Planned maintenance on B SBGT and B core spray systems the week of February 13, 2012
- Troubleshooting an electrical problem with a reactor protection system (RPS)electrical protection assembly during the week of February 20, 2012
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-2012-00517 concerning operability of the C RHR pump while its power cable was submerged due to flooding of an associated outside manhole when the manhole sump system stopped working, on January 16, 2012
- CR-JAF-2012-00414 concerning operability of D EDG fuel oil transfer pump 93P1-D1 with a measured flow rate of less than the minimum specified in an associated surveillance procedure, on January 20, 2012
- Engineering change (EC)-03-1947 which provided justification for plant operation up to 100 percent with two condensate booster pumps in service rather than the normal configuration of three pumps in service, on January 20, 2012
- CR-JAF-2012-01407 concerning operability of the control room emergency ventilation air supply system with an out of tolerance differential pressure switch that provides automatic system initiation on sensed low air flow, on March 9, 2012
- CR-JAF-2012-01491 concerning operability of the B RPS normal power supply electric protective assemblies (EPAs) following an unexpected overvoltage trip of one of the EPAs while attempting to transfer power to the normal supply, on March 15, 2012 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 TS and UFSAR to Entergy personnels 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 personnel. The inspectors determined, where appropriate, compliance with bounding limitations associated with the evaluations.
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.
- Work order (WO) 52230216-01, to perform ST-9QB, EDG B and D Full Load Test (8 Hour Run), Revision 8, as PMT for various maintenance activities performed on the D-EDG during the preceding five day maintenance period, on January 20, 2012
- WO 52381928-01, to perform ST-7F, Standby Gas Treatment Fan B and Valve Exercising (IST [in-service test]), Revision 5, as PMT for maintenance on various valves performed during the preceding two day maintenance period, on February 15, 2012
- WO 52242086 to perform 600 volt motor controller maintenance on the circuit breaker for B core spray outboard isolation valve 14MOV-11B, on February 16, 2012
- WO 00266452-03 for motor operated valve (MOV) electrical inspection of A RHR low pressure coolant injection (LPCI) outboard injection valve 10MOV-27A, on March 1, 2012
- WO 00284872 to replace the housing for B RHR service water filter 10S-5B1, on March 23, 2012
- WO 52267362 to perform 600 volt motor controller maintenance on the A SLC pump motor circuit breaker, on March 26, 2012
b. Findings
No findings were identified.
1R22 Surveillance Testing
a. Inspection Scope
The inspectors observed performance of surveillance tests (STs) and/or reviewed test data of selected risk-significant SSCs to assess whether test results satisfied technical specifications, 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 STs:
- ISP-40-4, EDG Remote Shutdown Electrical Meters Calibration, Revision 7, on February 17, 2012
- ST-3PB, Core Spray Loop B Quarterly Operability Test (IST), Revision 21, on February 16, 2012
[analog transmitter trip system]), Revision 36, on March 5, 2012
- ST-5BA, APRM [average power range monitor] System A Channel Functional Test, Revision 2, on March 8, 2012
- ST-9BB, EDG B and D Full Load Test and ESW [emergency service water] Pump Operability Test, Revision 12, on March 12, 2012
- ST-4N, HPCI Quick Start, Inservice, and Transient Monitoring Test (IST), Revision 61, on March 13, 2012
b. Findings
No findings were identified.
Cornerstone: Emergency Preparedness
1EP6 Drill Evaluation
.1 Emergency Preparedness Drill Observation
a. Inspection Scope
The inspectors evaluated the conduct of a routine FitzPatrick site emergency drill on February 22, 2012 to identify any weaknesses and deficiencies in the classification, notification, and protective action recommendation development activities. The inspectors observed emergency response operations in the simulator and technical support center (TSC) to determine whether the event classification, notifications, and protective action recommendations were performed in accordance with procedures. The inspectors also attended the TSC facility debrief and the station drill critique to compare inspector observations with those identified by Entergy staff in order to evaluate the station critique and to determine whether the Entergy staff was properly identifying weaknesses and entering them into the CAP.
b. Findings
No findings were identified.
.2 Training Observations
a. Inspection Scope
The inspectors observed a simulator training evolution for FitzPatrick licensed operators on January 30, 2012, which required emergency plan implementation by an operations crew. Entergy staff planned for this evolution to be evaluated and included in performance indicator (PI) data regarding drill and exercise performance. The inspectors observed event classification and notification activities performed by the crew.
The inspectors also attended the post-evolution critique for the scenario. The focus of the inspectors activities was to note any weaknesses and deficiencies in the crews performance and ensure that Entergy evaluators noted the same issues and entered them into the CAP.
b. Findings
No findings were identified.
OTHER ACTIVITIES
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.
4OA3 Follow-up of Events and Notices of Enforcement Discretion
.1 (Closed) Licensee Event Report (LER) 05000333/2010-005-01, High Pressure Coolant
Injection System Declared Inoperable due to Power Supply Degradation
a. Inspection Scope
On October 23, 2010, Entergy staff noted an acrid odor emanating from the HPCI instrument power inverter, as well as discoloration of the inverter casing due to localized overheating. Entergy personnel declared the HPCI system inoperable and replaced the degraded inverter. Later that day, Entergy personnel restored HPCI to operable status.
The system had been inoperable for approximately 20.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />. The inspectors reviewed the original LER, as documented in Inspection Report 05000333/2011002, and determined that no violation of regulatory requirements had occurred.
On January 7, 2011, the RCIC steam admission valve, 13MOV-131, did not fully open on demand during quarterly system surveillance testing. Subsequent investigation determined the cause to have been a loose connection in the 13MOV-131 motor control circuit. Because maintenance had last been performed on this circuit during the 2010 refueling outage, Entergy staff concluded that the RCIC system had been inoperable since October 16, 2010 (when the RCIC system was required to be operable during startup from the refueling outage), a period longer than allowed by the TS limiting condition for operation (LCO). A similar failure of 13MOV-131 to fully open had occurred on October 29, 2010, and had been attributed to a lack of stem lubrication. Entergy staff determined that the RCIC system, while inoperable, remained available during this time because 13MOV-131 would open sufficiently to provide steam for the RCIC system to perform its safety function.
On March 8, 2011, Entergy staff reported this event to the NRC in LER 2011-001-00.
During review of this LER, the inspectors noted that the assessment of safety consequences did not account for the period that the HPCI system had concurrently been inoperable on October 23, 2010. Although the RCIC system is not an emergency core cooling system (ECCS), it provides the same overall plant function of high pressure makeup inventory as the HPCI system. Therefore, TS 3.5.1.C provides a 14 day allowed outage time for the HPCI system, provided the RCIC system is operable.
Similarly, TS 3.5.3.A provides a 14 day allowed outage time for the RCIC system, provided the HPCI system is operable. However, if both systems are inoperable, TSs 3.5.1.G and 3.5.3.B require that the unit be placed in Mode 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and steam dome pressure be reduced to less than or equal to ( ) 150 pounds per square inch gauge (psig) within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. Because the HPCI system had been inoperable for greater than 20 hours2.314815e-4 days <br />0.00556 hours <br />3.306878e-5 weeks <br />7.61e-6 months <br /> on October 23, 2010, coincident with the RCIC system being inoperable, and the unit continued to operate in Mode 1 throughout that time, Entergy was required to report this as a TS 3.5.1.G violation. The original RCIC LER had been written due to violation of TS 3.5.3.B, however, Entergy staff had not addressed the impact of the coincident HPCI inoperability in the Event Analysis portion of the report until questioned by the inspectors.
As a result, on November 15, 2011, Entergy staff submitted revisions to both the HPCI and RCIC LERs. The inspectors reviewed and closed the RCIC LERs, 2011-001-00 and
-01, in Inspection Report 05000333/2011005, and issued Entergy a Green NCV for failing to identify and correct the cause of the failure of 13MOV-131 to fully open on October 29, 2010. Because the RCIC system was inoperable for approximately 84 days, the inspectors also noted in the NCV that RCIC had been inoperable for greater than its individual TS LCO allowed outage time. During this most recent inspection period, the inspectors reviewed the revised HPCI LER, which addressed the concurrent inoperability of the RCIC and HPCI systems.
b. Findings
Introduction:
The inspectors identified a Severity Level (SL) IV NCV of 10 CFR Part 50.73, Licensee Event Report System, because a violation of TS 3.5.1.G for the condition of HPCI and RCIC being simultaneously inoperable was not reported to the NRC within 60 days of discovery.
Description:
During review of the RCIC steam admission valve failure to fully open on January 7, 2011, Entergy staff concluded that the RCIC system had been inoperable since October 16, 2010. On March 8, 2011, Entergy submitted LER 2011-001-00, identifying that RCIC had been inoperable for greater than its TS LCO allowed outage time. However, Entergy staff did not identify that, for approximately 20 hours2.314815e-4 days <br />0.00556 hours <br />3.306878e-5 weeks <br />7.61e-6 months <br /> on October 23, 2010, the HPCI system had also been inoperable, resulting in an additional reportable condition (violation of TS 3.5.1.G). Based on this information having been available to Entergy personnel as of the submittal date of the original RCIC LER (March 8, 2011), the violation of TS 3.5.1.G should have been reported through a revision to the HPCI LER within 60 days. However, it was not until the inspectors identified the omission of HPCI inoperability in the RCIC LER on September 22, 2011, that Entergy personnel recognized an additional TS violation had occurred. After this was identified by the inspectors, the issue was entered into Entergys CAP as CR-JAF-2011-04779.
Entergy submitted Revision 1 to LERs 2010-005 and 2011-001 on November 15, 2011.
Analysis:
The inspectors determined that the failure to revise LER 2010-005 within 60 days to include the violation of TS 3.5.1.G in accordance with 10 CFR Part 50.73 was a performance deficiency that was reasonably within Entergys ability to foresee and correct, and should have been prevented. Because the issue impacted the regulatory process, in that a violation of site Technical Specifications was not reported to the NRC within the required timeframe, thereby delaying the NRCs opportunity to review the matter, the inspectors evaluated this performance deficiency in accordance with the traditional enforcement process. 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 Part 50.73 when information that the report was required had been reasonably within their ability to have identified. In accordance with IMC 0612, Appendix B, traditional enforcement issues are not assigned cross-cutting aspects.
The inspectors also reviewed the safety significance of the concurrent inoperability of the RCIC and HPCI systems for approximately 20 hours2.314815e-4 days <br />0.00556 hours <br />3.306878e-5 weeks <br />7.61e-6 months <br /> on October 23, 2010. The inspectors concluded that this condition was of very low safety significance because the failure of 13MOV-131 did not prevent the RCIC pump from achieving rated discharge flow and pressure and the pump remained capable of performing its design function during the period that the condition existed.
Enforcement:
10 CFR 50.73(a)(2)(B) requires, in part, that licensees shall submit a Licensee Event Report within 60 days after the discovery of any operation or condition which was prohibited by the plants TS (with certain exceptions). FitzPatrick renewed operating license DPR-59, Condition 2.C.2 states that Entergy personnel shall operate the facility in accordance with the TS. FitzPatrick TS 3.5.1 requires that each ECCS injection/spray subsystem and the Automatic Depressurization System function of six safety/relief valves shall be operable in mode 1. TS 3.5.1.C provides a 14 day allowed outage time if the HPCI system is inoperable, provided that the RCIC system is immediately verified to be operable. TS 3.5.1 Limiting Condition of Operation G states, in part, that if the required action and associated completion time of condition C is not met, the plant shall be in mode 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and reactor steam dome pressure reduced to 150 psig within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />.
Contrary to the above, on October 23, 2010, FitzPatricks HPCI system (an ECCS injection subsystem) and RCIC system were both inoperable, but the plant was not taken to mode 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and reactor steam dome pressure was not reduced to 150 psig within 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />. Entergy staff did not report that both systems were inoperable and the plant had been in a condition which was prohibited by TS within 60 days of discovery on March 8, 2011, even though the information to determine that the condition existed and such a report was required was within the licensees ability to identify. Upon identification by the inspectors that the HPCI and RCIC systems had both been inoperable for a period of time greater than allowed by TS, Entergy revised the original LERs and reported the TS violation. Because this SLIV violation was of very low safety significance, was not repetitive or willful, and was placed in the licensees CAP as CR-JAF-2011-04779, this violation is being treated as an NCV, consistent with Section 2.3.2 of the Enforcement Policy. (NCV 05000333/2012002-01, Failure to Submit an LER Revision for a Condition Prohibited by TS Associated with the HPCI System) This LER is closed.
4OA5 Other Activities
.1 (Closed) Unresolved Item (URI)05000333/2011004-01, Unplanned Power Reduction
Performance Indicator Reporting This URI was initiated because the inspectors questioned whether Entergy staffs not reporting three power reductions of greater than 20 percent that appeared not to have been planned 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> in advance was consistent with official guidance. The downpowers in question involved one power reduction due to main condenser tube leakage and two due to condenser fouling associated with intake traveling screen maintenance. The condenser fouling issue was subsequently reviewed through the NRC and industry PI frequently asked questions (FAQ) process and the associated power reductions were determined to have been reportable. This conclusion was entered into Entergys CAP as CR-JAF-2011-06230. In addition, after further consideration, Entergy staff did not pursue the condenser tube leak power reduction through the FAQ process. As a result, in their fourth quarter 2011 PI submittal, Entergy staff reported these three additional unplanned power reductions that had occurred during the second quarter of 2011.
In accordance with Inspection Procedure 71151, Performance Indicator Verification, this issue was determined to be minor because the additional unplanned power reductions did not cause the PI to cross a threshold or affect the plants ROP Action Matrix column designation. This URI is closed.
.2 Licensee Strike Contingency Plans
a. Inspection Scope
The contract between Entergy and the FitzPatrick site security department collective bargaining unit was due to expire during this inspection period. The inspectors evaluated the adequacy of Entergys strike contingency plan to determine if the required minimum number of qualified personnel were available for proper safety of the facility, and to determine if the plan complied with regulatory requirements and site security plan requirements. Prior to expiration, a new contract agreement was reached and subsequently ratified.
b. Findings
No findings were identified.
.3 Temporary Instruction 2515/182, Review of the Industry Initiative to Control Degradation
of Underground Piping and Tanks, Phase 1
a. Inspection Scope
Entergys buried piping and underground piping and tanks program was inspected in accordance with paragraphs 03.01a through 03.01c of the Temporary Instruction and was found to meet all applicable aspects of the Nuclear Energy Institute (NEI) document 09-14, Revision 1, as set forth in Table 1 of the Temporary Instruction 2515/182.
b. Findings
No findings were identified.
4OA6 Meetings, Including Exit
The inspectors presented the inspection results to Mr. M. Colomb and other members of Entergy management at the conclusion of the inspection on April 23, 2012. The inspectors asked Entergy personnel whether any materials examined during the inspection should be considered proprietary. No proprietary information was identified by Entergy personnel.
ATTACHMENT:
SUPPLEMENTARY INFORMATION
KEY POINTS OF CONTACT
Entergy Personnel
- M. Colomb, Site Vice President
- C. Adner, Manager, Operations
- V. Bacanskas, Manager, Design Engineering
- C. Brown, Manager, Quality Assurance, Entergy
- R. Brown, Acting Manager, Radiation Protection
- B. Finn, Director, Nuclear Safety Assurance
- D. Koelbel, Sr. Engineer, Fire Protection
- J. Pechacek, Manager, Licensing
- D. Poulin, Manager, System Engineering
- T. Raymond, Manager, Project Management
- T. Redfearn, Manager, Security
- M. Reno, Manager, Maintenance
- P. Scanlan, Manager, Programs and Components Engineering
- B. Sullivan, General Manager, Plant Operations
- D. Wallace, Director, Engineering
LIST OF ITEMS OPENED, CLOSED, DISCUSSED, AND UPDATED
Opened/Closed
- 05000333/2012002-01 NCV Failure to Submit an LER Revision for a Condition Prohibited by TS Associated with the HPCI System (Section 4OA3)
Closed
- 05000333/2010005-01 LER High Pressure Coolant Injection System Declared Inoperable due to Power Supply Degradation (Section 4OA3)
- 05000333/2011004-01 URI Unplanned Power Reduction Performance Indicator Reporting (Section 4OA5)
Discussed
- 05000333/2011001-00 and 01 LER Reactor Core Isolation Cooling System Inoperable Longer than Allowed by Technical Specifications (Section 4OA3)