IR 05000354/2013002
| ML13121A520 | |
| Person / Time | |
|---|---|
| Site: | Hope Creek  |
| Issue date: | 05/01/2013 |
| From: | Glenn Dentel Reactor Projects Branch 3 |
| To: | Joyce T Public Service Enterprise Group |
| dentel, gt | |
| References | |
| IR-13-002 | |
| Download: ML13121A520 (42) | |
Text
UNITED STATES NUCLEAR REGULATORY COMMISSION May 1, 2013
SUBJECT:
HOPE CREEK GENERATING STATION UNIT 1 - NRC INTEGRATED INSPECTION REPORT 05000354/2013002
Dear Mr. Joyce:
On March 31, 2013, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Hope Creek Generating Station (HCGS). The enclosed inspection report documents the inspection results, which were discussed on April 18, 2013, with Mr. E. Carr, Hope Creek Plant Manager, and other members of your staff.
The inspection examined activities conducted under your license as they relate to safety and compliance with the Commissions rules and regulations and with the conditions of your license.
The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.
This report documents one self-revealing non-cited violation (NCV) of very low safety significance (Green). This finding was determined to involve a violation of NRC requirements.
However, because of the very low safety significance, and because it was entered into your corrective action program, the NRC is treating these findings as NCVs, 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 20555-0001; with copies to the Regional Administrator, Region I; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at HCGS. In addition, if you disagree with the cross-cutting aspect assigned to any finding in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region I, and the NRC Resident Inspector at HCGS. In accordance with 10 CFR 2.390 of the NRCs Rules of Practice, a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRCs Public Document Room or from the Publicly Available Records component of the NRCs Agencywide Documents Access Management System (ADAMS). ADAMS is accessible from the NRC website at http://www.nrc.gov/reading-rm/adams.htmL (the Public Electronic Reading Room).
Sincerely,
/RA/
Glenn T. Dentel, Chief Reactor Projects Branch 3 Division of Reactor Projects Docket No.: 50-354 License No.: NPF-57
Enclosure:
Inspection Report 05000354/2013002 w/Attachment: Supplementary Information
REGION I==
Docket No.: 50-354 License No.: NPF-57 Report No.: 05000354/2013002 Licensee: PSEG Nuclear LLC (PSEG)
Facility: Hope Creek Generating Station (HCGS)
Location: P.O. Box 236 Hancocks Bridge, NJ 08038 Dates: January 1, 2013 through March 31, 2013 Inspectors: F. Bower, Senior Resident Inspector S. Ibarrola, Resident Inspector B. Scrabeck, Project Engineer J. Laughlin, Emergency Preparedness Inspector E. Burket, Emergency Preparedness Specialist S. Barr; Senior Emergency Preparedness Specialist Approved By: Glenn T. Dentel, Chief Reactor Projects Branch 3 Division of Reactor Projects Enclosure
SUMMARY
IR 05000354/2013002; 01/01/2013 - 03/31/2013; Hope Creek Generating Station; Follow-Up of
Events and Notices of Enforcement Discretion.
This report covered a three-month period of inspection by resident inspectors and announced inspections performed by emergency preparedness specialists. There was one self-revealing finding of very low safety significance (Green), which was a 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 (SDP), dated June 2, 2011. Cross-cutting aspects are determined using IMC 0310, Components Within Cross-Cutting Areas, dated October 28, 2011. All violations of NRC requirements are dispositioned in accordance with the NRCs Enforcement Policy, dated January 28, 2013. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process,
Revision 4.
Cornerstone: Mitigating Systems
- Green.
A self-revealing NCV of very low safety significance of technical specification (TS) 6.8.1 and TS 3.3.7.4 resulted because PSEG did not properly perform the monthly TS surveillance requirement (SR) 4.3.7.4.1 which demonstrates operability of the remote shutdown system instrumentation and controls. Specifically, operators that performed the monthly surveillance did not identify that the reactor core isolation cooling (RCIC) turbine bearing oil pressure low indication was inoperable and, as a result, PSEG did not take the action required within the TS allowed outage time. PSEGs immediate corrective actions included entering the issue into their corrective action program as notifications 20567832 and 20567743, replacing the failed relay and initiating an apparent cause evaluation (ACE).
This finding is more than minor because it is associated with the equipment performance attribute of the Mitigating Systems cornerstone and affected the cornerstone objective to ensure the availability and reliability of systems that respond to initiating events to prevent undesirable consequences. Specifically, when tested, the RCIC turbine bearing oil pressure low indication on the remote shutdown panel (RSP) was inoperable, and this condition went undetected for approximately one month. In accordance with IMC 0609.04, Initial Characterization of Findings, and Exhibit 2 of IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, issued June 19, 2012, the inspectors determined that this finding is of very low safety significance (Green) because the performance deficiency was not a design or qualification deficiency, did not involve an actual loss of safety function, did not represent actual loss of a safety function of a single train for greater than its TS allowed outage time, and did not screen as potentially risk-significant due to a seismic, flooding, or severe weather initiating event. The NRC determined the finding had a cross cutting aspect in the human performance area associated with work practices - procedural compliance, because PSEG did not ensure that personnel work practices support human performance, in that, a licensed reactor operator (RO) incorrectly documented HC.OP*ST.SV*0001 as satisfactory. Additionally, the senior reactor operator (SRO) that reviewed the test did not identify the procedure performance error
H.4(b). (Section 4OA3.1)
REPORT DETAILS
Summary of Plant Status
The Hope Creek Generating Station began the inspection period at or near full rated thermal power (RTP) where it generally remained until the end of the inspection period with the following exception. On March 2, power was reduced to approximately 76 percent RTP to support planned turbine valve testing and a control rod sequence exchange. Additional planned and contingency corrective maintenance activities were performed and the unit was returned to full power on March 3,
REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity
1R01 Adverse Weather Protection
.1 Readiness for Impending Adverse Weather Conditions
a. Inspection Scope
The inspectors reviewed PSEGs preparation activities for river grass intrusion conditions that may impact the station service water system. The inspectors assessed implementation of PSEGs grassing readiness plan through service water system reviews, corrective action program reviews, and discussions with cognizant plant personnel. Documents reviewed for each section of this inspection report are listed in the Attachment.
b. Findings
No findings were identified.
1R04 Equipment Alignment
.1 Partial System Walkdowns
a. Inspection Scope
The inspectors performed partial walkdowns of the following systems:
A, B, and D safety auxiliary cooling systems (SACS) pumps with the C SACS pump and 1EG-HV-2522C valve out-of-service on January 7, 2013 A, B, and D emergency diesel generators (EDGs) with the C EDG out-of-service for emergent maintenance on February 6, 2013 B, C, and D main steam line (MSL) pressure transmitters, and other primary containment isolation system instruments with the A MSL pressure transmitter sensing line out-of-service for emergent maintenance on February 27, 2013 A, B, and D EDGs with the C EDG out-of-service for planned maintenance on March 8, 2013 The inspectors selected these systems based on their risk-significance for the current plant configuration or following realignment. The inspectors reviewed applicable procedures, system diagrams, the Updated Final Safety Analysis Report (UFSAR), TSs, work orders, notifications, 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 also performed field walkdowns of accessible portions of the systems to verify system components and support equipment were aligned correctly and were operable.
b. Findings
No findings were identified.
.2 Full System Walkdown
a. Inspection Scope
On January 14 - 17, 2013, the inspectors performed a complete system walkdown of accessible portions of the A and C residual heat removal (RHR) systems to verify the equipment lineup was correct. The inspectors reviewed operating procedures, surveillance tests, drawings, equipment lineup procedures, 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. The inspectors also reviewed whether PSEG staff had properly identified equipment issues and entered them into the corrective action program for resolution with the appropriate significance characterization. Additionally, the inspectors reviewed a sample of related notifications and work orders to ensure PSEG 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 PSEG controlled combustible materials and ignition sources were 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.
FRH-II-414, A and C core spray rooms, elevation 54 on January 15, 2013 FRH-II-411, B and D core spray rooms, elevation 54 on January 15, 2013 FRH-II-413, A RHR heat exchanger room, elevation 54 on January 17, 2013 FRH-II-552, electrical access area, elevation 137 on February 5, 2013 FRH-II-541, class 1E switchgear rooms, elevation 130 on March 28, 2013
b. Findings
No findings were identified.
.2 Fire Protection - Drill Observation
a. Inspection Scope
The inspectors observed an unannounced fire brigade drill scenario conducted on February 7, 2013, that involved a fire in the Hope Creek service water intake structure, Room 201. The inspectors evaluated the readiness of the plant fire brigade to fight fires.
The inspectors verified that PSEG personnel identified deficiencies; openly discussed them in a self-critical manner at the post-drill 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 Smoke removal operations 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 PSEGs fire-fighting strategies.
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 corrective action program to determine if PSEG identified and corrected flooding problems and whether operator actions for coping with flooding were adequate. The inspectors also focused on high pressure coolant injection (HPCI) and RCIC batteries and electrical equipment room areas (5104, 5128, 5129, 5130) and the EDG fuel oil transfer pumps and storage tanks room areas (5107, 5108, 5109, 5110) to verify the adequacy of common drain lines and sumps, sump pumps, level alarms, and control circuits.
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 the first licensed operator simulator training session on January 22, 2013, that included a fire, a grid transient, a loss of coolant accident (LOCA), and a loss of offsite power (LOOP) coincident with the loss of one EDG.
On February 5, 2013, the inspectors observed a second licensed operator simulator training session that included a fire, a grid transient, a LOCA and a LOOP coincident with the loss of one EDG. 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
The inspectors observed and reviewed a planned downpower and main steam valve and turbine valve testing conducted on March 2, 2013. The inspectors observed reactivity control briefings to verify that the briefings met the criteria specified in OP-AA-101-111-1004, Operations Standards, Revision 4, and HU-AA-1211, Pre-Job Briefings, Revision 10. Additionally, the inspectors observed test performance to verify that procedure use, crew communications, and coordination of activities between work groups similarly 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, and component (SSC) performance and reliability. The inspectors reviewed corrective action program documents (notifications),maintenance work orders (orders), and maintenance rule basis documents to ensure that PSEG 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 PSEG 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 PSEG staff was identifying and addressing common cause failures that occurred within and across maintenance rule system boundaries.
Reactor water cleanup (RWCU) isolation differential flow transmitter found out of acceptable value (Notification 20596152)
C EDG over speed knob will not reset following post maintenance testing (Notification 20598212)
b. Findings
No findings were identified.
1R13 Maintenance Risk Assessments and Emergent Work Control
a. Inspection Scope
The inspectors reviewed station evaluation and management of plant risk for the maintenance and emergent work activities listed below to verify that PSEG performed the appropriate risk assessments prior to removing equipment for work. The inspectors selected these activities based on potential risk significance relative to the reactor safety cornerstones. As applicable for each activity, the inspectors verified that PSEG personnel performed risk assessments as required by 10 CFR 50.65(a)(4) and that the assessments were accurate and complete. When PSEG performed emergent work, the inspectors verified that operations personnel promptly assessed and managed plant risk.
The inspectors reviewed the scope of maintenance work and discussed the results of the assessment with the stations probabilistic risk analyst to verify plant conditions were consistent with the risk assessment. The inspectors also reviewed the TS requirements and inspected portions of redundant safety systems, when applicable, to verify risk analysis assumptions were valid and applicable requirements were met.
Planned maintenance and inoperability of the A EDG during January 29-31, 2013 (Order 30203217)
Emergent inoperability, troubleshooting, and corrective maintenance for the C EDG during February 4-6, 2013 (Order 60108706)
Emergent inoperability, troubleshooting, and corrective maintenance for the A MSL pressure transmitter sensing line on February 26-27, 2013 (Order 60109132)
Planned maintenance and inoperability of the C EDG during March 4-9, 2013 (Order
===30210543)
Emergent inoperability, troubleshooting, and corrective maintenance for the A loop of RHR suppression pool spray isolation valve, BC-HV-F027A, during March 12-13, 2013 (Order 60109275)
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:
Slight drop in B reactor recirculation pump 2nd stage seal pressure on December 30, 2013 (Notification 20589009)
Evaluation of D traveling water screen non-drive jib key weld broken on January 21, 2013 (Order 70148402)
Safety relief valve F013R high tailpipe temperature alarm on January 29, 2013 (Notification 20593312)
C EDG frequency oscillation on February 4, 2013 (Order 80108609)
Evaluation of reactor recirculation loop sample line inboard containment isolation valve, 1BBSV-4310, local position indication test failure on February 10, 2013 (Order 80108731)
Evaluation of B traveling water screen headshaft shifted on February 10, 2013 (Order 70149442)
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 technical specifications and UFSAR to PSEGs 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 PSEG. The inspectors determined, where appropriate, compliance with bounding limitations associated with the evaluations.
b. Findings
No findings were identified.
1R18 Plant Modifications
.1 Permanent Modifications
a. Inspection Scope
The inspectors evaluated a modification to the RWCU system implemented by design change package 80102453, Replace Reactor Water Cleanup Recirculation Pump 1A-A-221. The existing centrifugal horizontal pump was replaced with a vertical, wet stator seal-less pump design to address longstanding mechanical seal leakage issues associated with the existing pump. The inspectors verified that the design bases, licensing bases, and performance capability of the affected systems were not degraded by the modification. In addition, the inspectors reviewed modification documents associated with the upgrade and design change, including original pump and support structure removal and installation of new seismic support structure from overhead structural steel, replacement of the RWCU pump isolation valves, and modification of reactor auxiliaries cooling system supply and return lines. The inspectors also reviewed revisions to the control room alarm response procedure and interviewed engineering and operations personnel to ensure the procedure could be reasonably performed.
b. Findings
No findings were identified.
.2 Temporary Modifications
a. Inspection Scope
The inspectors reviewed the temporary modifications listed below to determine whether the modifications affected the safety functions of systems that are important to safety.
The inspectors reviewed 10 CFR 50.59 documentation, post-modification testing results, and conducted field walkdowns of the modifications to verify that the temporary modifications did not degrade the design bases, licensing bases, and performance capability of the affected systems.
Temporary Configuration Change Package Number 4HT-13-001, Revision 0 -
Install Temporary Submersible Pumps in Manholes 15MM0D06, 15MM0D08, and 15MM0D08B Temporary Configuration Change Package Number 4HT-13-002, Revision 0 -
Jumper C EDG Jacket Water Keepwarm Heater H1KJ-1C-E-407
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.
D RHR loop minimum flow valve planned maintenance on January 23, 2013 (Order 30106244)
A EDG planned maintenance on January 30, 2013 (Order 60099516)
A EDG repair of an emergent jacket water piping joint leak on January 31, 2013 (Notification 20593491 and Order 60108553)
A RWCU recirculation pump replacement on February 14, 2013 (Order 60098001)
A loop torus spray isolation valve, BC-HV-027A, emergent breaker and thermal overload maintenance on March 13, 2013 (Order 60109275)
B core spray loop planned preventive maintenance and motor control center design changes on March 21, 2013 (Order 30107170)
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 PSEG 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:
HC.OP-IS.BC-0001, A RHR pump (AP202) in-service test on January 4, 2013 HC.OP-IS.BE-0101, Core spray subsystem A valves test on January 10, 2013 HC.OP-IS.BE-0001, A & C core spray pumps test (AP206 and CP206) on January 10, 2013 HC.OP-IS.BJ-0002, HPCI jockey pump AP228 in-service test - quarterly, on January 12, 2013 HC.OP-IS.BJ-0101, HPCI valves in-service test - quarterly, on January 12, 2013 HC.OP-IS.BC-0003, B RHR pump (BP202) in-service test on January 16, 2013 HC.OP-DL.ZZ-0026, Drywell floor drain leakage monitoring on February 4, 2013
b. Findings
No findings were identified.
Cornerstone: Emergency Preparedness
1EP2 Alert and Notification System Evaluation
a. Inspection Scope
An onsite review was conducted to assess the maintenance and testing of the Alert and Notification System (ANS). During this inspection, the inspectors conducted a review of the ANS testing and maintenance programs. The inspectors reviewed the associated ANS procedures and the Federal Emergency Management Agency approved ANS Design Report to ensure compliance with design report commitments for system maintenance and testing. The inspection was conducted in accordance with NRC Inspection Procedure 71114, Attachment 2. 10 CFR 50.47(b)(5) and the related requirements of 10 CFR Part 50, Appendix E, were used as reference criteria.
b. Findings
No findings were identified.
1EP3 Emergency Response Organization Staffing and Augmentation System (71114.03 -
1 sample)
a. Inspection Scope
The inspectors conducted a review of the Hope Creek Emergency Response Organization (ERO) augmentation staffing requirements and the process for notifying and augmenting the ERO. The review was performed to verify the readiness of key PSEG staff to respond to an emergency event and to verify PSEGs ability to activate their emergency response facilities (ERFs) in a timely manner. The inspectors reviewed PSEGs Emergency Plan for ERF activation and ERO staffing requirements, the ERO duty roster, applicable station procedures, augmentation test reports, the most recent drive-in drill report, and corrective action reports (notifications) related to this inspection area. The inspectors also reviewed a sample of ERO responder training records to verify training and qualifications were up to date. The inspection was conducted in accordance with NRC Inspection Procedure 71114, Attachment 3. 10 CFR 50.47(b)(2)and related requirements of 10 CFR Part 50, Appendix E, were used as reference criteria.
b. Findings
No findings were identified.
1EP4 Emergency Action Level and Emergency Plan Changes
a. Inspection Scope
NRC staff from the Office of Nuclear Security and Incident Response performed an in-office review of the latest revisions of various Emergency Plan Implementing Procedures and the Emergency Plan located under ADAMS accession number ML123250117 and ML12348A140.
PSEG determined that in accordance with 10 CFR 50.54(q), the changes made in the revisions resulted in no reduction in the effectiveness of the Emergency Plan, and that the revised Emergency Plan continued to meet the requirements of 10 CFR 50.47(b)and Appendix E to 10 CFR Part 50. The NRC review was not documented in a safety evaluation report and did not constitute approval of PSEG-generated changes; therefore, this revision is subject to future inspection.
b. Findings
No findings were identified.
1EP5 Maintaining Emergency Preparedness
a. Inspection Scope
The inspectors reviewed a number of activities to evaluate the efficacy of PSEGs efforts to maintain the Hope Creek emergency preparedness (EP) program. The inspectors reviewed: Memorandums of Understanding with offsite agencies; the 10 CFR 50.54(q)
Emergency Plan change process and practice; PSEG maintenance of equipment important to EP; records of evacuation time estimate population evaluation; and provisions for, and implementation of, primary, backup, and alternate ERF maintenance.
The inspectors also verified PSEGs compliance at Hope Creek with new NRC EP regulations regarding: emergency action levels for hostile action events; protective actions for onsite personnel during events; emergency declaration timeliness; ERO augmentation and alternate facility capability; evacuation time estimate updates; on-shift ERO staffing analysis; and ANS back-up means.
The inspectors further evaluated PSEGs ability to maintain their EP programs through their identification and correction of EP weaknesses, by reviewing a sample of drill reports, actual event reports, self-assessments, 10 CFR 50.54(t) audits, and EP-related notifications. The inspectors reviewed a sample of EP-related notifications initiated at Hope Creek from March 2011 through March 2013. The inspection was conducted in accordance with NRC Inspection Procedure 71114.05. 10 CFR 50.47(b) and the related requirements of 10 CFR Part 50, Appendix E, were used as reference criteria.
b. Findings
No findings were identified.
1EP6 Drill Evaluation
.1 Emergency Preparedness Drill Observation
a. Inspection Scope
The inspectors evaluated the conduct of a routine Hope Creek emergency drill on February 5, 2013, 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 and simulator facilities drill critiques to compare inspector observations with those identified by PSEG staff in order to evaluate Hope Creeks critique and to verify whether the PSEG staff was properly identifying weaknesses and entering them into the corrective action program.
b. Findings
No findings were identified.
.2 Training Observations
a. Inspection Scope
The inspectors observed a simulator training evolution for licensed operators on January 22, 2013, which required emergency plan implementation by an operations crew. PSEG planned for this evolution to be evaluated and included in performance indicator data regarding drill and exercise performance. The inspectors observed event classification 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 PSEG evaluators noted the same issues and entered them into the corrective action program.
b. Findings
No findings were identified.
OTHER ACTIVITIES
4OA1 Performance Indicator Verification
.1 Unplanned Scrams, Unplanned Power Changes, and Unplanned Scrams with
Complications ===
a. Inspection Scope
The inspectors reviewed PSEGs submittal of the following Hope Creek Initiating Events Cornerstone performance indicators for the period of January 1, 2012, through December 31, 2012.
Unplanned (automatic and manual) Scrams per 7,000 critical hours Unplanned Power Changes per 7,000 critical hours Unplanned Scrams with Complications To determine the accuracy of the performance indicator data reported during those periods, the inspectors used definitions and guidance contained in Nuclear Energy Institute (NEI) Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6. The inspectors reviewed Hope Creeks monthly operating reports and NRC integrated inspection reports to validate the accuracy of the submittals.
b. Findings
No findings were identified.
.2 Safety System Functional Failures (1 sample)
a. Inspection Scope
The inspectors sampled PSEGs submittals for the Safety System Functional Failures performance indicator for Hope Creek for the period of January 1, 2012, through December 31, 2012. To determine the accuracy of the performance indicator data reported during those periods, inspectors used definitions and guidance contained in NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, and NUREG-1022, Event Reporting Guidelines 10 CFR 50.72 and 10 CFR 50.73. The inspectors reviewed PSEGs licensee event reports (LERs) to validate the accuracy of the submittals.
b. Findings
No findings were identified.
.3 Emergency Preparedness (3 samples)
a. Inspection Scope
The inspectors reviewed data for the following EP performance indicators:
Drill and Exercise Performance ERO Drill Participation ANS Reliability The last NRC EP inspection at Hope Creek was conducted in the second calendar quarter of 2012. Therefore, the inspectors reviewed supporting documentation from EP drills and equipment tests from the second calendar quarter of 2012 through the fourth calendar quarter of 2012 to verify the accuracy of the reported performance indicator data. The review of the performance indicators was conducted in accordance with NRC Inspection Procedure 71151. The acceptance criteria documented in NEI 99-02, Regulatory Assessment Performance Indicator Guidelines, Revision 6, was used as reference criteria.
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 PSEG entered issues into the corrective action program 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 corrective action program.
b. Findings
No findings were identified.
.2 Annual Sample: Review of the Operator Workaround Program
a. Inspection Scope
The inspectors reviewed the cumulative effects of the existing operator workarounds, operator burdens, existing 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 PSEG procedures:
OP-AA-102-103, Operator Work-Around Program OP-AA-102-103-1001, Operator Burdens Program OP-AA-102-103, Operator Burden Assessment The inspectors reviewed PSEGs 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 PSEG assessment of operator burdens. The inspectors also toured the control room and discussed the current operator workarounds with the operators to ensure the items were being 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 PSEG 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.
4OA3 Follow-Up of Events and Notices of Enforcement Discretion
.1 (Closed) LER 05000354/2012-005-00: RCIC Bearing Low Oil Pressure Indication on
Remote Shutdown Panel Inoperable
a. Inspection Scope
On July 15, 2012, the performance of monthly surveillance identified that the remote indication for the RCIC bearing oil low pressure alarm was inoperable. The Shift Manager entered the action statement for TS 3.3.7.4. Preliminary investigation showed that normally energized relay E51-K58 had malfunctioned. The relay was replaced and operability restored on July 16, 2012. During the investigation into the cause of the failed indication, PSEG personnel reviewed the previous surveillance test that was performed on June 16, 2012, and determined that the alarm indication was extinguished and incorrectly documented in the test as satisfactory. Therefore, the RCIC bearing oil low pressure alarm indication on the remote shutdown panel was inoperable between June 16, 2012, and July 16, 2012. TS 3.3.7.4.a requires restoration of this inoperable channel within seven days or be in at least Hot Shutdown within the next 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. This issue was reported under 10 CFR 50.73(a)(2)(i)(B) as a condition prohibited by TSs.
b. Findings
Introduction.
A Green self-revealing NCV of TS 3.3.7.4 and TS 6.8.1 resulted because PSEG did not properly perform the monthly TS SR 4.3.7.4.1 which demonstrates operability of the remote shutdown system instrumentation and controls. Specifically, operators that performed PSEG procedure HC.OP-ST.SV-0001 did not identify that the RCIC turbine bearing oil pressure low indication was inoperable and, as a result, PSEG did not take the action required within the TS allowed outage time.
Description.
On July 15, 2012, during the performance of a TS-required surveillance test, HC.OP-ST.SV-0001, Remote Shutdown Monitoring Instrumentation Channel Check - Monthly, identified that the remote indication for the RCIC bearing oil low pressure alarm was inoperable. The alarm annunciator was extinguished when it should have been illuminated because the RCIC pump was not running. The loss of the RSP indication was caused by a failed relay in the indication circuit. The relay was subsequently replaced and retested (Notification 20567832, Order 60104604) on July 16, 2012. PSEGs ACE determined that the normally energized relay failed due to age-related wear. A review of service history determined the relay was beyond its service life. Planned corrective actions for the relay failure include changing the relays preventive maintenance (PM) frequency and reviewing the PM frequency for other normally energized relays in the RSP.
PSEGs review of the previous months surveillance performed on June 16, 2012, identified that at that time, the alarm annunciator, which should have been illuminated, was extinguished; but the licensed RO who performed the surveillance had incorrectly documented the test as satisfactory. In addition, the licensed SRO who reviewed and approved the completed surveillance also missed the error. The condition went undetected until the next performance of HC.OP-ST.SV-0001 on July 15, 2012. This single channel RSP indication was inoperable for longer than the allowed outage time in TS 3.3.7.4.a. PSEGs ACE concluded that the apparent cause for this violation occurred because surveillance procedure HC.OP-ST.SV-0001 was not performed correctly on June 16, 2012. The inspectors determined that this issue was self-revealing because PSEGs previous performance of the same surveillance on June 16, 2012, should have identified the inoperable indication but did not because operators did not perform the procedure correctly and it required minimal analysis to detect the past inoperability.
Contributing causes were that the SRO that reviewed the test did not identify the procedure performance error and that HC.OP-ST.SV-0001, as written, could lead a performer to misinterpret the acceptance criteria. PSEGs corrective actions for the human performance issues that led to the TS violation included delimiting the qualifications of both operators and requiring remedial training to be completed prior to resuming licensed operator duties and enhancing the procedure to clarify the acceptance criteria (Notification 20567743, Order 70141127).
PSEGs ACE also observed that this condition existed for at least a month even though the RSP area is toured on a shiftly basis by non-licensed equipment operators (EOs)who perform general area checks in accordance with OP-AA-111-101-1001, Use and Development of Operating Logs. Additionally, the auxiliary building logs required that once per week, on Monday night, the EOs were to perform RSP lamp checks and verify that the RSP indications were consistent with plant conditions. PSEGs ACE noted that EOs were not trained or qualified to operate the controls at the RSP, perform none of the operations testing at the RSP, and as such do not possess the RO level knowledge to verify the proper status and indications of the RSP. Corrective actions included reassigning these responsibilities to control room ROs (Notification 20567743, Order 70141127).
Analysis.
The inspectors determined that PSEGs failure to correctly implement HC.OP-ST.SV-0001 for SR 4.3.7.4.1 on June 16, 2012, to demonstrate the operability of the RCIC turbine bearing oil pressure low indication on the RSP was a performance deficiency that was within PSEGs ability to foresee and correct, and should have been prevented. As a result of the inadequate implementation, the failed RSP instrument went undetected and PSEG did not take the action required to restore operability of the instrument within the TS allowed outage time. This finding is more than minor because it is associated with the equipment performance attribute of the Mitigating Systems cornerstone and affected the cornerstone objective to ensure the availability and reliability of systems that respond to initiating events to prevent undesirable consequences. Specifically, when tested, the RCIC turbine bearing oil pressure low indication on the RSP was inoperable, and this condition went undetected for approximately one month. In accordance with IMC 0609.04, Initial Characterization of Findings, and Exhibit 2 of IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, issued June 19, 2012, the inspectors determined that this finding is of very low safety significance (Green) because the performance deficiency was not a design or qualification deficiency, did not involve an actual loss of safety function, did not represent actual loss of a safety function of a single train for greater than its TS allowed outage time, and did not screen as potentially risk-significant due to a seismic, flooding, or severe weather initiating event.
The NRC determined the finding had a cross-cutting aspect in the human performance area associated with work practices-procedural compliance, because PSEG did not ensure that personnel work practices support human performance, in that, a licensed RO incorrectly documented HC.OP-ST.SV-0001 as satisfactory. Additionally, the SRO that reviewed the test did not identify the procedure performance error. (H.4(b))
Enforcement.
TS 3.3.7.4, Remote Shutdown System Instrumentation and Controls, requires one operable channel of RCIC turbine bearing oil pressure low indication in Operational Conditions 1 and 2. With the RCIC RSP instrumentation inoperable, the associated Limiting Condition for Operation, TS 3.3.7.4.a, requires restoration of this inoperable channel within seven days or be in at least Hot Shutdown within the next 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
TS 6.8.1 requires, in part, that written procedures shall be established, implemented, and maintained covering the activities in Appendix A of Regulatory Guide 1.33, Revision 2, February 1978. Section 8.b(2)(I) of Appendix A of Regulatory Guide 1.33 states, in part, that specific implementing procedures are required for each surveillance test or calibration listed in the TSs. TS SR 4.3.7.4.1 specifies that each of the required remote shutdown monitoring instrumentation channels shall be demonstrated operable by performance of a channel check. PSEG procedure HC.OP-ST.SV-0001, Remote Shutdown Monitoring Instrumentation Channel Check - Monthly, Revision 25, requires documenting whether specified acceptance criteria to demonstrate operability were met, including whether the status of the RCIC turbine bearing oil low pressure indication light was SAT or UNSAT for the current RCIC system status (i.e., illuminated if out of service, not illuminated if in service).
Contrary to the above, on June 16, 2012, PSEG failed to properly implement HC.OP-ST.SV-0001, to demonstrate operability of the remote shutdown system instrumentation and controls in that all acceptance criteria were marked SAT (and the system was considered to be operable) even though the RCIC turbine bearing oil low pressure indication light was not illuminated and the RCIC system was out of service. As a result, between June 16, 2012, and July 16, 2012, the RCIC turbine bearing oil low pressure indication on the RSP remained inoperable for a time in excess of that allowed by TS 3.3.7.4.a, and PSEG did not restore this single channel of instrumentation within seven days and was not in Hot Shutdown within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. PSEGs immediate corrective actions included entering this issue into their corrective action program as notifications 20567832 and 20567743, replacing the failed relay, and initiating an ACE.
Because this violation was of very low safety significance (Green), and PSEG entered this issue into their corrective action program (notifications 20567832 and 20567743),this violation is being treated as an NCV, consistent with Section 2.3.2 of the Enforcement Policy. (NCV 05000354/2013002-01, A Technical Specification Surveillance Procedure for Remote Shutdown Panel Instrumentation was Inadequately Implemented)
.2 (Closed) LER 05000354/2012-006-00: High Pressure Coolant Injection System
Inoperable On September 4, 2012, PSEG was running the HPCI system for its quarterly in-service test, HC.OP-IS.BJ-0001, HPCI Main and Booster Pump Set - 0P204 and 0P217 - In Service Test. In parallel and in accordance with the procedure, the operator started the HPCI auxiliary oil pump and opened the HPCI steam admission valve, 1FD-HV-F001, but the HPCI steam admission valve did not stroke open as indicated by observation of control room position indication, zero turbine speed indicated on the HPCI speed controller, and local position. Operators aborted the test and the Shift Manager declared the HPCI system inoperable.
PSEG determined through troubleshooting that there was no continuity through a normally closed contact on the motor-operator limit switch contact (LS-11). With the F001 valve in a less than fully open position, the LS-11 contact should be closed to provide power to the valve opening control circuit. Power to the opening circuit remains sealed in until the F001 reaches its full open limit switch. The F001 will not open without continuity through the LS-11 contacts. Visual inspection of the compartment did not find any component out of position and did not identify grease or debris that could have prevented LS-11 from making contact. PSEG cleaned and adjusted the contacts. A subsequent continuity check was satisfactory. The HPCI F001 valve retested satisfactorily. PSEG placed the issue into the corrective action program as notification 20574697.
PSEG determined through its root cause evaluation that station procedures did not provide enhanced limit switch inspection guidance to prevent high resistance conditions.
The inspectors determined this was not a performance deficiency because it was not within PSEGs ability to foresee and prevent this condition. Specifically, this contact was last cleaned and inspected for its 10-year environmental qualification preventive maintenance in November 2007. The valve was also successfully stroked numerous times following the last maintenance performed during RF17. PSEGs corrective actions included procedure revisions to provide adequate limit switch inspection guidance and installing a design change that will verify continuity across the 1FD-HV-F001 valve opening circuit. The inspectors did not identify any new issues during the review of this LER. This LER is closed.
4OA6 Meetings, Including Exit
On April 18, 2013, the inspectors presented the inspection results to Mr. E. Carr, Hope Creek Plant Manager, and other members of the Hope Creek 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
- J. Perry, Site Vice President
- E. Carr, Plant Manager
- C. Banner, Emergency Preparedness Manager
- B. Boesch, Hope Creek Training Manager
- P. Bonnett, Regulatory Assurance
- D. Bush, System Engineer
- E. Casuli, Plant Engineering Manager
- S. Connelly, System Engineering
- T. Fowler, Operations Training Manager
- J. Kandasamy, Work Management Director
- K. Knaide, Engineering Director
- W. Kopchick, Operations Director
- V. McPherson, Maintenance Superintendent
- J. Molner, Emergency Preparedness Station Manager
- F. Mooney, Maintenance Director
- T. Morin, Regulatory Assurance
- S. Simpson, Regulatory Assurance Manager
- H. Trimble, Radiation Protection Manager
LIST OF ITEMS OPENED, CLOSED, DISCUSSED, AND UPDATED
Opened/Closed
- 05000354/2013002-01 NCV A Technical Specification Surveillance Procedure for Remote Shutdown Panel Instrumentation was Inadequately Implemented (Section 4OA3.1)
Closed
- 05000354/2012-005-00 LER RCIC Bearing Low Oil Pressure Indication on Remote Shutdown Panel Inoperable (Section 4OA3.1)
- 05000354/2012-006-00 LER High Pressure Coolant Injection System Inoperable (Section 4OA3.2)