IR 05000333/2013005
| ML14042A129 | |
| Person / Time | |
|---|---|
| Site: | FitzPatrick  |
| Issue date: | 02/11/2014 |
| From: | Arthur Burritt Reactor Projects Branch 2 |
| To: | Coyle L Entergy Nuclear Northeast |
| Burritt A | |
| References | |
| IR 13-005 | |
| Download: ML14042A129 (34) | |
Text
February 11, 2014
SUBJECT:
JAMES A. FITZPATRICK NUCLEAR POWER PLANT - NRC INTEGRATED INSPECTION REPORT 05000333/2013005
Dear Mr. Coyle:
On December 31, 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 January 23, 2014, 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 Severity Level IV violation. 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.
As a result of the Safety Culture Common Language Initiative, the terminology and coding of cross-cutting aspects were revised beginning in calendar year (CY) 2014. New cross-cutting aspects identified in CY 2014 will be coded under the latest revision to Inspection Manual Chapter (IMC) 0310. Cross-cutting aspects identified in the last six months of 2013 using the previous terminology will be converted to the latest revision in accordance with the cross-reference in IMC 0310. The revised cross-cutting aspects will be evaluated for cross-cutting themes and potential substantive cross-cutting issues in accordance with IMC 0305 starting with the CY 2014 mid-cycle assessment review. In accordance with Title 10 of the Code of Federal Regulations 2.390, Public Inspections, Exemptions, Requests for Withholding, 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.
Enclosure:
Inspection Report No. 05000333/2013005
w/Attachment: Supplementary Information
REGION I==
Docket No:
50-333
License No:
Report No:
Licensee:
Entergy Nuclear Northeast (Entergy)
Facility:
James A. FitzPatrick Nuclear Power Plant
Location:
Scriba, NY
Dates:
October 1, 2013 through December 31, 2013
Inspectors:
E. Knutson, Senior Resident Inspector
B. Sienel, Resident Inspector
J. Brand, Reactor Inspector
S. McCarver, Physical Security Inspector
J. Nicholson, Health Physicist
S. Pindale, Senior Reactor Inspector
R. Rolph, Health Physicist
T. Setzer, Senior Project Engineer
Approved by:
Arthur L. Burritt, Chief Reactor Projects Branch 2 Division of Reactor Projects
Enclosure
SUMMARY
IR 05000333/2013005; 10/01/2013 - 12/31/2013; James A. FitzPatrick Nuclear Power Plant (FitzPatrick); Problem Identification and Resolution.
This report covered a three-month period of inspection by resident inspectors and announced inspections performed by regional inspectors. Inspectors identified one Severity Level IV non-cited violation (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, 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 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 4.
Cornerstone: Initiating Events
Severity Level IV. The inspectors identified a Severity Level IV (SL IV) NCV of Title 10 of the Code of Federal Regulations (10 CFR) 50.72, Immediate Notification Requirements for Operating Nuclear Power Reactors, because unplanned inoperability of the high pressure coolant injection (HPCI) system was not reported to the NRC within eight hours of when it should reasonably have been discovered, as required by 10 CFR 50.72(b)(3)(v), Event or Condition that Could Have Prevented Fulfillment of a Safety Function. Specifically, identification that issues with two of the condensate storage tank (CST) level detectors that provide automatic transfer of the HPCI suction from the CSTs to the suppression pool would have caused this transfer to occur at less than the minimum CST level allowed by Technical Specifications (TSs) and therefore caused the HPCI system to be inoperable, was not promptly recognized as a condition reportable under 10 CFR 50.72. This issue was entered into the corrective action program (CAP) as condition report (CR)-JAF-2013-06344.
The inspectors determined that the failure to inform the NRC of the HPCI 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. 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, 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 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 4OA2)
REPORT DETAILS
Summary of Plant Status
James A. FitzPatrick Nuclear Power Plant (FitzPatrick) began the inspection period at 100 percent power. On October 19, 2013, operators reduced power to 50 percent to address main condenser tube leakage. Operators further utilized the period of reduced power operations to perform single control rod scram time testing, channel-control blade interference testing, and a control rod sequence exchange. Following completion of these activities and identification and repair of the main condenser tube leak, operators restored power to 100 percent the following day. On October 21, 2013, operators reduced power to 75 percent to perform a control rod pattern adjustment and restored power to 100 percent later that day. On four other occasions (November 6, November 10, December 9, and December 25, 2013), operators performed similar short duration power reductions to 50 percent to address main condenser tube leakage.
On December 22, 2013, operators reduced power to 65 percent to remove the C condensate booster pump from service to replace its lube oil cooler and restored power to 100 percent later that day. On December 31, 2013, operators reduced power to 75 percent to isolate a main condenser water box due to tube leakage and remained at 75 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 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 HPCI, reactor core isolation cooling (RCIC), and emergency diesel generator (EDG) 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
.
b. Findings
No findings were identified.
==1R04 Equipment Alignment
Partial System Walkdown (71111.04 - 3 samples)
a. Inspection Scope
==
The inspectors performed partial walkdowns of the following systems:
A and C EDGs while D EDG was inoperable for planned maintenance on October 22, 2013
B and D EDGs while offsite 115 kilovolt (kV) Line 4 was unavailable due to planned offsite maintenance on November 14, 2013
A residual heat removal (RHR) system while B RHR and RHR service water (RHRSW) systems were inoperable for planned maintenance on November 20, 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 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.
==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 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.
West electric bay, fire area/zone IC/SW-1, on October 2, 2013
Cable spreading room, fire area/zone VII/CS-1, on October 16, 2013 Reactor building 369 foot elevation, fire area/zone IX/RB-1A, on November 11, 2013
A battery room, battery charger room, and corridor, fire area/zones III/BR-1, BR-2, and BR-5, on December 9, 2013
B battery room and battery charger room, fire area/zones III/BR-3 and BR-4, on December 9, 2013
b. Findings
No findings were identified.
.2 Fire Protection - Drill Observation
a. Inspection Scope
The inspectors observed an unannounced fire brigade drill conducted on October 30, 2013, that involved a fire in the cable spreading room. 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.
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 23, 2013, which included a small break loss of coolant accident, tornado, and reactor 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 October 1, 2013, the inspectors observed operator response to the failure of a traversing incore probe (TIP) to retract during testing. This required entry into a four hour shutdown limiting condition of operation for primary containment. The inspectors observed crew performance to verify that procedure use, crew communications, and coordination of activities between work groups met established expectations and standards.
On December 10, 2013, the inspectors observed power ascension following condenser tube plugging, including reactivity manipulations using control rods and the reactor recirculation system. 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 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.
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:
115 kV Line 3 and reserve station service transformer T-2 planned maintenance and emergent TIP probe failure the week of October 1, 2013
Emergent B RHRSW strainer maintenance the week of October 6, 2013
Planned maintenance on the D EDG the week of October 21, 2013
Planned maintenance on B RHR and RHRSW systems the week of November 18, 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-2013-05595 concerning low HPCI and RCIC area temperatures, on November 5, 2013
CR-JAF-2013-01738 and CR-JAF-2013-05988 concerning emergency service water piping supplying the west crescent area unit coolers beyond its calculated remaining service life, on November 25, 2013
CR-JAF-2013-06042 concerning past operability of the A EDG in light of a governor control circuit malfunction that was identified prior to monthly surveillance testing, on December 6, 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 compliance with bounding limitations associated with the evaluations.
b. Findings
No findings were identified.
1R18 Plant Modifications
a. Inspection Scope
The inspectors reviewed temporary modification engineering change (EC) 47612, Control Rod 18-07 Indicates Full Out/48 but Rod Drift Annunciator 09-5-2-3 Alarming.
Use Full Out Contact Until PIP [position indicating probe] Can Be Repaired. In this modification, a probe buffer card was installed for control rod 18-07 that had been modified to use the duplicate position 48 indicator such that both the four rod display and the EPIC computer position for this rod would indicate position 48, while clearing the invalid rod drift alarm. The inspectors reviewed 10 CFR 50.59 documentation and discussed the change with the cognizant system engineer to verify that the temporary modification did not degrade the design bases, licensing bases, and performance capability of the manual rod control system.
b. Findings
No findings were identified.
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.
Work order (WO) 52397243 to perform preventive maintenance on the D EDG air start left bank relay valve, on October 25, 2013
WO 349248-01 to replace HPCI auto isolation instrument master trip unit (MTU)23MTU-294A, on October 30, 2013 WO 52038333 to replace 2-3MTU-273, on November 6, 2013
WO 00294998 to perform major preventive maintenance on B RHR heat exchanger bypass valve, 10MOV-66B, on November 21, 2013
WO 52341487 to inspect and clean the B RHRSW heat exchanger, on November 21, 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:
ST-24J, RCIC Flow Rate and Inservice Test (IST), on October 7, 2013
ISP-107A, RPS [reactor protection system] Drywell Pressure Instrument Response Time Test (ATTS) [analog transmitter trip system]**, on October 10, 2013
ST-4N, HPCI Quick-Start, Inservice, and Transient Monitoring Test (IST), on October 28, 2013
ISP-175A1, Reactor and Containment Cooling Instrument Functional Test/
Calibration (ATTS)**, on November 6, 2013
b. Findings
No findings were identified.
RADIATION SAFETY
Cornerstone: Occupational/Public Radiation Safety
2RS1 Radiological Hazard Assessment and Exposure Controls
a. Inspection Scope
The inspectors reviewed and assessed FitzPatrick staffs performance in assessing the radiological hazards and exposure control in the workplace. The inspectors used the requirements in 10 CFR 20 and guidance in Regulatory Guide (RG) 8.38, Control of Access to High and Very High Radiation Areas for Nuclear Plants, TSs, and the Entergy procedures required by TSs as criteria for determining compliance.
Inspection Planning
The inspectors reviewed 2013 Entergy performance indicators for the occupational exposure cornerstone for FitzPatrick. The inspectors reviewed the results of Radiation Protection program audits. The inspectors reviewed any reports of operational occurrences related to occupational radiation safety since the last inspection.
Radiological Hazard Assessment
The inspectors selected the core spray pump surveillance as a risk-significant work activity that involved exposure to radiation.
For this work activity, the inspectors assessed whether the pre-work surveys performed were appropriate to identify and quantify the radiological hazard and to establish adequate protective measures. The inspectors evaluated the radiological survey program to determine if radiological hazards were properly identified.
Instructions to Workers
The inspectors selected three containers holding non-exempt licensed radioactive materials and assessed whether the containers were labeled and controlled in accordance with regulatory requirements.
Contamination and Radioactive Material Control
The inspectors observed one location where Entergy staff monitored potentially contaminated material leaving the radiological control area, and inspected the methods used for control, survey, and release of materials from this area. The inspectors observed the performance of personnel surveying and releasing material and evaluated whether the work was performed in accordance with procedures. The inspectors assessed whether the radiation monitoring instrumentation used for equipment release and personnel contamination surveys had appropriate sensitivity for the type(s) of radiation present.
The inspectors reviewed Entergy staffs criteria for the survey and release of potentially contaminated material. The inspectors evaluated whether there was guidance on how to respond to an alarm.
The inspectors reviewed Entergys procedures and records to verify that the radiation monitoring instrumentation was used at a low detection sensitivity. The inspectors selected two sealed sources from Entergys inventory records and assessed whether the sources were accounted for and were tested for loose surface contamination.
The inspectors examined Entergys physical and programmatic controls for highly activated or contaminated materials stored within spent fuel and other storage pools.
The inspectors assessed whether appropriate controls were in place to preclude inadvertent removal of these materials from the pool.
Risk-Significant High Radiation Area and Very High Radiation Area Controls
The inspectors discussed with the Radiation Protection Manager the controls and procedures for high-risk High Radiation Areas and Very High Radiation Areas (VHRAs).
The inspectors discussed with first-line health physics supervisors the controls in place for special areas that have the potential to become VHRAs during certain plant operations.
The inspectors evaluated Entergys controls for VHRAs and areas with the potential to become a VHRA to ensure that an individual was not able to gain unauthorized access to these VHRAs.
b. Findings
No findings were identified.
2RS5 Radiation Monitoring Instrumentation
a. Inspection Scope
The inspectors reviewed the accuracy and operability of radiation monitoring. The inspectors used the requirements in 10 CFR 20, applicable industry standards, and Entergys procedures required by TSs as criteria for determining compliance.
The inspectors selected five portable survey instruments in use or available for issuance and assessed calibration and source check stickers for currency, as well as instrument material condition and operability.
b. Findings
No findings were identified.
2RS6 Radioactive Gaseous and Liquid Effluent Treatment
a. Inspection Scope
The inspectors ensured that the gaseous and liquid effluent processing systems were maintained so that radiological discharges were properly mitigated, monitored, and evaluated with regard to public exposure. The inspectors used the requirements in 10 CFR 20; 10 CFR 50.35(a); TSs; 10 CFR 50, Appendix A, Criterion 60, Control of Release of Radioactivity to the Environment, and Criterion 64, Monitoring Radioactive Releases; 10 CFR 50, Appendix I, Numerical Guides for Design Objectives and Limiting Conditions for Operations to Meet the Criterion As Low as is Reasonably Achievable (ALARA) for Radioactive Material in Light-Water-Cooled Nuclear Power Reactor Effluents; 10 CFR 50.75(g), Reporting and Recordkeeping for Decommissioning Planning; 40 CFR 141, Maximum Contaminant Levels for Radionuclides; 40 CFR 190, Environmental Radiation Protection Standards for Nuclear Power Operations; the guidance in RGs 1.109, 1.21, 4.1 and 4.15; NUREGs 1301 and 1302, Offsite Dose Calculation Manual Guidance (ODCM):
Standard Radiological Effluent Control, as well as applicable Industry standards; and Entergy procedures required by the FitzPatrick TSs/ODCM as criteria for determining compliance.
Groundwater Protection Initiative Program
The inspectors reviewed reported groundwater monitoring results and changes to Entergys written program for identifying and controlling contaminated spills/leaks to groundwater.
b. Findings
No findings were identified.
OTHER ACTIVITIES
4OA1 Performance Indicator Verification
.1 Mitigating Systems Performance Index (5 samples)
a. Inspection Scope
The inspectors reviewed FitzPatrick staffs submittal of the Mitigating Systems Performance Index (MSPI) for the following systems for the period of October 1, 2012, through September 30, 2013.
MSPI, emergency alternating current power system
MSPI, high pressure injection system
MSPI, heat removal system
MSPI, residual heat removal system
MSPI, cooling water systems
To determine the accuracy of the performance indicator (PI) data reported during this period, the inspectors used definitions and guidance contained in Nuclear Energy Institute (NEI) Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, and discussed specific questions with the responsible system engineer. The inspectors also reviewed FitzPatrick operator narrative logs, CRs, NRC integrated inspection reports, and the FitzPatrick MSPI bases document to validate the accuracy of the submittals.
b. Findings
No findings were identified.
.2 Occupational Exposure Control Effectiveness (1 sample)
a. Inspection Scope
The inspector sampled Entergy submittals for the occupational exposure control effectiveness PI for the period from the fourth quarter 2012 through third quarter 2013.
The inspectors used PI definitions and guidance contained in the NEI Document 99-02, Revision 7, to determine the accuracy of the PI data reported.
To assess the adequacy of Entergys PI 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 PI 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 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
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 HPCI system was not reported to the NRC within eight hours of when it should reasonably have been discovered, as required by 10 CFR 50.72(b)(3)(v),
Event or Condition that Could Have Prevented Fulfillment of a Safety Function.
Specifically, identification that issues with two of the CST level detectors that provide automatic transfer of the HPCI suction from the CST to the suppression pool would have caused this transfer to occur at less than the minimum CST level allowed by TS and therefore caused the HPCI system to be inoperable, was not promptly recognized as a condition reportable under 10 CFR 50.72.
Description.
On the morning of December 17, 2013, technicians commenced surveillance test ISP-75, HPCI CST Low Water Level Switch Functional Test/Calibration. The purpose of this test is to verify proper operation of the four CST level switches that provide input to the circuit that controls automatic transfer of the HPCI suction from the two cross-connected CSTs to the suppression pool, in the event that CST inventory has been depleted. The test also satisfies TS surveillance requirements 3.3.5.1.3 and 3.3.5.1.6 to perform periodic channel calibrations and logic system functional tests. TS Table 3.3.5.1-1, Emergency Core Cooling System Instrumentation, specifies that the allowable value for CST level at which automatic transfer must occur is greater than or equal to 59.5 inches.
During the test, the technicians determined that one of the B CST level switches, 23LS-74B, did not actuate until after it had been mechanically agitated. Operators declared the switch inoperable and entered TS 3.3.5.1.D, which required that the switch be placed in the tripped condition within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Subsequently, the technicians identified that the second B CST level switch, 23LS-75B, actuated at 58.5 inches, one inch less than the minimum TS-specified value. The switch did not require mechanical agitation to operate, and the technicians adjusted its setpoint to the desired value as allowed by the test procedure. The remainder of the test procedure was completed at 11:04 a.m.,
without further issue. Operators entered the two B CST level switch issues into the CAP as CR-JAF-2013-06304 and CR-JAF-2013-06306.
Operators evaluated the as-found condition of the HPCI automatic suction transfer feature against the reportability requirements of 10 CFR 50.72. Engineering staff evaluated the condition and determined that the suction transfer occurring at one inch below the TS-minimum allowable value would not result in a loss of HPCI suction due to vortex formation in the CSTs. Operators concluded that the as-found condition had not constituted a condition that could have prevented fulfillment of the HPCI 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 morning, the inspectors reviewed the HPCI CST level switch 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 HPCI system operability, NRC Inspection Manual Part 9900, Operability Determination Process, states, In order to be considered operable, an SSC must be capable of performing the safety functions specified by its design... In addition, TS operability considerations require that an SSC meet all surveillance requirements (as specified in Surveillance Requirement (SR) Applicability SR 3.0.1). An SSC that does not meet an SR must be declared inoperable. Although, in the as-found condition, the HPCI system had been capable of performing its design function, the automatic suction transfer feature had failed SR 3.3.5.1.3 and 3.3.5.1.6. Therefore, the inspectors determined that, in the as-found condition, the HPCI system had been inoperable. Given that the inoperability was due, in part, to equipment failure (failure of 23LS-74B to actuate), and that no redundant equipment was operable, in that the HPCI system is a single train system, the inspectors concluded that the HPCI CST level switch issue was reportable under 10 CFR 50.72(b)(3)(v).
The inspectors discussed this issue with FitzPatrick licensing department personnel and at 6:56 p.m. on December 18, 2013, operators reported this event to the NRC in accordance with 10 CFR 50.72(b)(3)(v)(D). This issue was entered into the CAP as CR-JAF-2013-06344.
Analysis.
The inspectors determined that the failure to inform the NRC of the HPCI 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. 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, 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 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)(D) 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 mitigate the consequences of an accident.
Contrary to the above, on December 17, 2013, at 11:04 a.m., completion of surveillance test procedure ISP-75 provided information that identified that the as-found condition of the HPCI automatic suction transfer feature, and therefore, of the HPCI system, had been inoperable, but this information was not promptly recognized by Entergy personnel and was not reported to the NRC until December 18, 2013, at 6:56 p.m., a period of approximately 32 hours3.703704e-4 days <br />0.00889 hours <br />5.291005e-5 weeks <br />1.2176e-5 months <br />. Because this SL IV violation was of very low safety significance, was not repetitive or willful, and was placed in the Entergys CAP as CR-JAF-2013-06344, this violation is being treated as an NCV, consistent with Section 2.3.2 of the Enforcement Policy. (NCV 05000333/2013005-01, Untimely 10 CFR 50.72 Notification of a HPCI System Functional Failure)
.2 Semi-Annual Trend Review (1 sample)
a. Inspection Scope
The inspectors performed a semi-annual review of site issues, as required by Inspection Procedure 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, PIs, system health reports, and CAP backlogs. The inspectors also reviewed Entergys CAP database for the third and fourth quarters of 2013 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 quarterly trend reports for the second and third quarters of 2013, conducted under EN-LI-121, Entergy Trending 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 trend reports. 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. For example, the inspectors noted that neutron monitoring system performance issues were appropriately being tracked as adverse trends. Also, the inspectors noted that emergency plan communications related issues that were identified as a possible trend by the inspectors during the previous 6-month trend review, were being tracked as an emerging trend.
.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 recent FitzPatrick staff evaluations 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 corrective action program at an appropriate threshold and planned or implemented corrective actions commensurate with their safety significance.
.4 Annual Sample:
Motor-Operated Valve Program Challenges (1 sample)
a. Inspection Scope
The inspectors performed an in-depth review of Entergy staffs evaluation and corrective actions associated with the potential for delayed implementation of Joint Owners Group (JOG) Motor-Operated Valve (MOV) program commitments. Specifically, during the 2012 refueling outage, Entergy staff discovered that the completion of several MOV calculations required significant offsite and contractor support to ensure their commitments associated with MOV periodic verification within six years of the associated NRC safety evaluation (dated September 25, 2006) would be completed.
The inspectors assessed Entergy staffs apparent cause evaluation (ACE), associated extent-of-condition reviews, and the prioritization and timeliness of actions to evaluate whether Entergy was appropriately identifying, characterizing, and correcting problems associated with the issue; and whether the planned or completed corrective actions were appropriate and met the requirements of Entergys CAP. The inspectors reviewed the applicable CR (CR-JAF-2012-05412) and associated documents. Specifically, the inspectors reviewed Entergy staffs identification of weaknesses and corrective actions, as well as additional actions to address other contributing causes identified in the ACE.
The inspectors also interviewed engineering personnel to assess the acceptability and effectiveness of the evaluation and implemented corrective actions.
b. Findings and Observations
No findings were identified.
The inspectors determined that Entergy staff had appropriately identified the apparent cause of not implementing the MOV program in a timely and effective manner as lack of management support for the program, and a contributing cause as inadequate tracking.
Although not specifically identified as a cause, Entergy staff also identified a lack of engineering experience within the MOV program. In addition, Entergy staff identified that the MOV program supervisory function was filled with several acting supervisors; the MOV program engineer had not received the proper training to perform the necessary MOV calculations; and turnover amongst several program supervisors as well as that for the MOV program engineer was weak. Entergy staff also reviewed the potential for similar challenges in other programs, such as fire protection and the air-operated valve (AOV) programs, and recommended appropriate actions.
The inspectors observed that Entergy staff documented the final program status to the NRC via a letter dated September 25, 2012, and determined that Entergy staff had completed the calculations required to implement the JOG MOV program. The inspectors also noted that seven of the calculations were beyond the expertise of the staff at the site; and contractor support as well as MOV engineer support from corporate Entergy headquarters and other Entergy sites was required to complete the effort.
The inspectors reviewed Entergy staffs corrective actions, which included internal operating experience sharing, communication of lessons-learned, and formalizing program turnovers. These actions notwithstanding, the inspectors noted that the lack of engineering experience within the MOV program was a factor in the delayed recognition of the magnitude of the effort needed to complete the implementation of the JOG MOV commitments. Also, significant resource sharing was necessary from other sites and Entergy headquarters to complete the effort.
At the time of the inspection, challenges with the experience level within the program remained in that the MOV program engineer position was vacant and the AOV program engineer was fulfilling both the AOV and MOV program functions. Furthermore, the corporate position of MOV program engineer was recently eliminated. While Entergy staff stated that they are aggressively pursuing efforts to fill the MOV program engineer position and program development efforts are now complete, the inspectors determined that the low experience and staffing levels represent continuing challenges within the MOV program.
.5 Annual Sample:
Multiple Installed In-Service Test (IST) Code Required Relief Valves
Not Tested Within The 10-Year Required Frequency (1 sample)
a. Inspection Scope
The inspectors performed an in-depth review of Entergy staffs root cause analysis and corrective actions associated with in-service testing (IST) of safety relief valves documented in condition reports CR-JAF-2012-05130, CR-JAF-2012-05043, CR-JAF-2012-05049, CR-JAF-2012-05054, CR-JAF-2012-05060, CR-JAF-2012-05063, and CR-JAF-2012-05064. Specifically, 13 out of 28 relief valves were identified as potentially not being tested or replaced within their required 10-year frequency. The valves affected were in safety-related and non-safety related systems including; the RHR system, the HPCI system, the core spray system, and the standby liquid control system.
The inspectors assessed FitzPatrick staffs problem identification threshold, cause analysis, extent-of-condition reviews, compensatory actions, and the prioritization and timeliness of applicable corrective actions to evaluate whether the FitzPatrick staff was appropriately identifying, characterizing, and correcting problems associated with this issue and whether the planned or completed corrective actions were appropriate. In addition, the inspectors compared the actions taken to the requirements of FitzPatricks CAP and 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action. The inspectors also interviewed engineering, licensing, operations, and IST component engineering staff to discuss relief valves performance issues and associated corrective actions.
b. Findings and Observations
No findings were identified.
The inspectors noted that not testing relief valves within the required 10-year frequency dates back to 2007. Per the root cause evaluation for CR-JAF-2012-05130, prior corrective actions implemented to revise the preventive maintenance frequencies based on valves test/certification dates did not prevent repeat of the condition because the action did not consider future valve replacements. Specifically, the preventive maintenance was automatically zeroed on the valve installation date in the electronic data base instead of the certification/test date. This allowed scheduling a testing and replacement activity of some relief valves beyond the 10 year test-to-test requirement.
The inspectors determined that Entergy staff appropriately identified, characterized, and implemented new corrective actions to address the repeat condition associated with relief valves not being tested or replaced within the required 10-year frequency. The inspectors verified that subsequent valve replacements and, as applicable for some valves, the required as-found IST was performed and the test results were satisfactory.
The inspectors also determined that operability of the associated safety-related systems was not impacted by the failure to implement the required IST testing and replacement activities within the required 10-year frequency because when the valves were subsequently tested, all acceptance criteria were met and the valves remained capable of performing the intended safety function.
The inspectors also verified that, for thermal relief valves which do not require as-found IST testing, the valves were properly replaced. However, inspectors noted that corrective actions for two of the relief valves had not been completed and may exceed their required 10-year frequency by the middle of 2014. Specifically, 10RV-41B, RHR Pump B Suction Relief, was initially scheduled to be done while the plant was operating. However, the work could not be done because of challenges with isolation of the line (CR-JAF-2013-05842). This issue notwithstanding, the inspectors verified that adequate plans were in place to replace the valve during the next refueling outage, and that engineering evaluations were planned to extend the service time of 10RV-41B.
A second valve, 10RV-43A, RHR Heat Exchanger A Tube Side Relief, had not been completed because there was no available certified replacement. The inspectors verified that actions were being implemented to install a qualified replacement valve by February 2014. The 10-year frequency for this valve ends on July 22, 2014.
4OA3 Follow-Up of Events and Notices of Enforcement Discretion
.1 (Closed) Licensee Event Report (LER) 05000333/2012-003-00:
High Pressure Coolant Injection System Inoperable Due to Air in Flow Element Sensing Line
On September 2, 2012, the HPCI flow indicating controller took a step increase from zero to approximately 700 gallons per minute, while the HPCI system was in standby.
As a result, the HPCI system may not have automatically achieved rated flow and therefore was declared inoperable. FitzPatrick staff determined that HPCI system maintenance activities that had commenced on August 30, 2012, had drained a portion of the main suction piping and introduced air into the flow element sensing lines. These lines were subsequently filled in accordance with an approved procedure; however, some air remained trapped due to the lines being inappropriately sloped relative to the main suction piping. As corrective action, the sensing lines were repeatedly flushed in the opposite direction to eliminate the remaining air. The HPCI system was tested and returned to operable on September 4, 2012.
The inspectors reviewed this LER and identified no violations of regulatory requirements.
Although the flow element sensing lines are not sloped in accordance with the design, they operate properly once they have been adequately vented. This LER is closed.
4OA5 Other Activities
.1 Operation of an Independent Spent Fuel Storage Installation (ISFSI) at Operating Plants
(60855 - 1 sample and 60855.1 - 1 sample)
a. Inspection Scope
On November 4-8, 2013, the inspectors observed and evaluated Entergys loading of a multi-purpose canister (MPC #18) associated with their ISFSI dry cask campaign for 2013. The inspectors also reviewed Entergys activities related to long-term operation and monitoring of their ISFSI. The inspectors verified compliance with the Certificate of Compliance (CoC), TS, regulations, and Entergy procedures.
The inspectors observed cask processing operations including: cask blowdown, welding of the lid to the MPC, hydrostatic testing, non-destructive examination of the lid weld, vacuum drying of the MPC, helium back filling of the MPC, and preparations for transport. During performance of these activities, the inspectors evaluated Entergys familiarity with procedures, supervisory oversight, and communication and coordination between the personnel involved. The inspectors attended Entergy briefings to assess their ability to identify critical steps of the evolution, potential failure scenarios, and human performance tools to prevent errors. The inspectors reviewed loading and monitoring procedures and evaluated Entergys adherence to these procedures. The inspectors also reviewed the training of personnel assigned to ISFSI activities.
The inspectors reviewed Entergys program associated with fuel characterization and selection for storage. The inspectors reviewed a cask fuel selection package to verify that Entergy was loading fuel in accordance with the CoC and TS. The inspectors confirmed that Entergy did not plan to load any damaged fuel assemblies during this campaign.
The inspectors reviewed radiation protection procedures and radiation work permits associated with the ISFSI loading campaign. The inspectors also reviewed the ALARA goal for the cask loading to determine the adequacy of Entergys radiological controls and to ensure that radiation worker doses were ALARA, and that project dose goals could be achieved. The inspectors reviewed radiological survey records from the current loading campaign to confirm that dose levels on the HI-TRAC and HI-STORM surface were as expected.
The inspectors performed a tour of the heavy haul path and ISFSI pad to assess the material condition of the path, pad, and the loaded HI-STORM. The inspectors verified Entergy was appropriately performing daily HI-STORM vent temperature surveillances in accordance with TS requirements. The inspectors also verified that transient combustibles were not being stored on the ISFSI pad or in the vicinity of the HI-STORM.
The annual environmental reports were reviewed to verify that areas around the ISFSI site boundary were within limits specified in 10 CFR 20 and 10 CFR 72.104. The inspectors reviewed Entergys 10 CFR 72.48 screenings to verify that they had appropriately considered the conditions under which they may make changes without prior NRC approval. The inspectors reviewed revisions to the 10 CFR 72.212 report.
The inspectors also reviewed CAP CRs, audit reports, and self-assessments that were generated since Entergys last loading campaign to ensure that issues were being properly identified, prioritized, and evaluated commensurate with their safety significance.
b. Findings
No findings were identified.
.2 Inspection Procedure 92723 Follow-up Inspection for Three or More Severity Level IV
Traditional Enforcement Violations in the Same Area in a 12-Month Period
a. Inspection Scope
On December 13, 2013, inspectors completed an in-office review of Entergys evaluation (CR-JAF-2013-02388) of three SL IV traditional enforcement violations, which were documented in NRC Inspection Report 05000333/2013002. These three violations occurred within the same traditional enforcement area of impeding the regulatory process. Entergys evaluation was a collective review of a total of six traditional enforcement violations, which included three violations documented in 05000333/2013002 and three earlier traditional enforcement violations that occurred in 2011 and early 2012. All six violations were within the same traditional enforcement area of impeding the regulatory process.
The objectives of the inspection were:
To provide assurance that the cause(s) of multiple SL IV traditional enforcement violations are understood by Entergy
To provide assurance that the extent of condition and extent of cause of multiple SL IV traditional enforcement violations are identified
To provide assurance that Entergy corrective actions to traditional enforcement violations are sufficient to address the cause
To review corrective actions resulting from the NRC 92723 inspection conducted in the 4th quarter of 2012
The inspectors reviewed CRs, procedures, and relevant references to the violations.
The inspectors also interviewed management and staff personnel who participated in the evaluation of the violations. The inspection criteria used during the inspection included the inspection guidance contained in NRC Inspection Procedure (IP) 92723 and the performance attributes listed in Table 1 of NRC IP 71152.
This inspection also included a review of Entergy corrective actions (CR-JAF-2012-08880) resulting from the NRC IP 92723 inspection conducted in the fourth quarter of 2012 and documented in NRC Integrated Inspection Report 05000333/2012005.
b. Findings
and Assessments
No findings were identified.
The inspectors reviewed Entergys high tier ACE (CR-JAF-2013-02388) and determined that it met all the inspection objectives of NRC IP 92723. However, the inspector noted the following observations during the review:
Entergys lack of readiness for this inspection caused a delay in completing this inspection. Specifically, the extent of condition and extent of cause corrective actions were not complete at the beginning of this inspection. Entergy completed a pre-inspection assessment in August 2013 using procedure EN-LI-123-03, Pre-Inspection Assessments for IP 92723. The assessment did not identify that corrective actions necessary for the inspection (extent of condition and extent of cause reviews) were not completed. This issue did not constitute a violation of regulatory requirements since Entergy procedure EN-LI-123-03 is an informational use, non-quality related procedure that is not required to be implemented by Entergys license. Entergy entered this issue into their CAP (CR-JAF-2013-06215).
Entergys evaluation identifies the apparent cause as being associated with inadequate management skills associated with the oversight of the Licensing department. Specifically, a site manager with considerable plant operations experience and knowledge was placed in the position of Licensing Manager in August 2012 without having been previously trained or experienced in licensing matters. This, coupled with a lack of experience and inadequate staffing, caused Entergy to be unable to consistently manage the licensing responsibilities at FitzPatrick, and resulted in a failure to report events to the NRC on multiple occasions. Entergy assigned corrective actions to perform work product reviews and interviews of staff-level employees to evaluate their current level of experience and qualifications, and to determine if any vulnerability exists as it did in the Licensing department. However, there are no corrective actions assigned to explore the selection process to determine how or why a site manager with no training or experience in licensing matters was assigned the position of Licensing Manager.
The inspector determined that the failure to develop corrective actions for the identified apparent cause as required by Entergy procedure EN-LI-119 was a performance deficiency of minor significance, and is not subject to enforcement in accordance with the NRCs Enforcement Policy. This issue has been entered into Entergys CAP (CR-JAF-2013-06215).
The extent of condition review generated corrective actions to perform work product reviews and interviews of staff to evaluate their current level of experience and qualifications, and to determine if any vulnerability exists as it did in the Licensing department. Entergy selected the Radiation Protection, Security, Design Engineering, and System Engineering departments in their extent of condition review. There is no documented basis or rationale why other departments or programs that interface with the NRC (Operations, Emergency Planning) were excluded in the extent of condition review. Similarly, there are no corrective actions to determine if there are any weaknesses within these other departments which the NRC relies upon for reporting accurate information in a timely manner. This issue has been entered into Entergys CAP (CR-JAF-2013-06215).
The inspector reviewed Entergys corrective actions (CR-JAF-2012-08880) resulting from the NRC IP 92723 inspection conducted in the fourth quarter of 2012 and documented in NRC Integrated Inspection Report 05000333/2012005. The NRC determined in that inspection that Entergy had not met the objectives of IP 92723.
Specifically, Entergy staff did not conduct a collective evaluation or implement a systematic method to evaluate the group of violations to determine common causes or ascertain whether there were commonalities amongst the group of violations.
Entergys evaluation identifies job unfamiliarity, inadequate work practices, lack of resources, and a backlog of licensing work as the apparent cause. Entergys corrective actions included performing a snapshot self-assessment and holding briefings of the licensing department to inform them of the causes. The inspector determined that the corrective actions contained in CR-JAF-2012-0880 were reasonable.
4OA6 Meetings, Including Exit
On January 23, 2014, 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, Systems 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
Untimely 10 CFR 50.72 Notification of a HPCI
System Functional Failure (Section 4OA2)
Closed
- 05000333/2012-003-00
LER
High Pressure Coolant Injection System Inoperable Due to Air in Flow Element Sensing Line (Section 4OA3)