IR 05000354/2013003
| ML13212A010 | |
| Person / Time | |
|---|---|
| Site: | Hope Creek  |
| Issue date: | 07/31/2013 |
| From: | Glenn Dentel Reactor Projects Branch 3 |
| To: | Joyce T Public Service Enterprise Group |
| DENTEL, GT | |
| References | |
| IR-13-003 | |
| Download: ML13212A010 (49) | |
Text
July 31, 2013
SUBJECT:
HOPE CREEK GENERATING STATION UNIT 1 - NRC INTEGRATED INSPECTION REPORT 05000354/2013003
Dear Mr. Joyce:
On June 30, 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 July 18, 2013, with Mr. E. Carr, Plant Manager of Hope Creek, 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). The finding is determined to involve a violation of NRC requirements.
However, because of the very low safety significance, and because it is entered into your corrective action program (CAP), the NRC is treating the finding as a NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy. If you contest any 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 accordance with 10 Code of Federal Regulations (CFR) 2.390 of the NRCs Rules of Practice, a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRCs Public Document Room or from the Publicly Available Records component of the NRCs Agencywide Documents Access 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 05000354/2013003
w/Attachment: Supplementary Information
REGION I==
License No.:
Report No.:
Licensee:
Public Service Enterprise Group (PSEG) Nuclear LLC
Facility:
Hope Creek Generating Station (HCGS)
Location:
P.O. Box 236
Hancocks Bridge, NJ 08038
Dates:
April 1, 2013, through June 30, 2013
Inspectors:
F. Bower, Senior Resident Inspector
D. Dodson, Acting Senior Resident Inspector
S. Ibarrola, Resident Inspector R. Barkley, Senior Project Engineer
R. Fuhrmeister, Senior Reactor Engineer
G. Bjorkman, Senior Technical Advisor
S. Hammann, Senior Health Physicist
R. Nimitz, Senior Health Physicist D. Lawyer, Health Physicist
Approved By:
Glenn T. Dentel, Chief
Reactor Projects Branch 3
Division of Reactor Projects
Enclosure
SUMMARY
IR 05000354/2013003; 04/01/2013 - 06/30/2013; 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 regional inspectors. Inspectors identified one self-revealing Green 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. All violations of Nuclear Regulatory Commission (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 Green NCV of Technical Specifications (TS) 6.8.1, Procedures, was identified because PSEG failed to establish an appropriate preventive maintenance (PM) schedule for Tyco/Agastat General Purpose (GP) control relays. Specifically, the evaluation PSEG performed to revise the relay replacement periodicity from 22 years to 40 years neither adequately addressed available relay references nor all applicable failure mechanisms. As a result, high pressure coolant injection (HPCI) failed to respond to logic system actuation signals during surveillance testing on April 8, 2013. PSEGs immediate corrective actions included replacing failed relays and placing the issues in the corrective action program (CAP). Additionally, PSEG plans to revise the replacement frequency and to replace other Tyco/Agastat GP control relays of high safety significance, as identified in their extent of condition review.
This finding was more than minor because it was associated with the equipment performance attribute of the mitigating systems cornerstone and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the failure of a control relay caused the HPCI system to fail to automatically actuate during testing, and the HPCI system was unexpectedly declared inoperable. The inspectors evaluated the finding in accordance with IMC 0609, Significance Determination Process, issued June 2, 2011, and determined the finding is of very low safety significance (Green) following a detailed risk evaluation. No cross-cutting aspect was assigned to this finding because PSEG decisions made with regard to evaluating the PM replacement periodicity were made more than 3 years ago and a PM Ownership Committee has since been created to review PM change evaluations; therefore, this performance deficiency is not reflective of current plant performance. (Section 4OA3)
REPORT DETAILS
Summary of Plant Status
Hope Creek began the inspection period at full rated thermal power (RTP). On May 8, 2013, operators reduced power to approximately 99 percent RTP following an emergent failure of the A and B reactor recirculation pump (RRP) speed control uninterruptible power supply (UPS).
On May 9, 2013, operators reduced power to approximately 98 percent RTP to reset the A and B RRP scoop tubes and isolate the speed control UPS for corrective maintenance. Operators returned the unit to full power on the same day. On May 10, 2013, operators reduced power to approximately 98 percent RTP to restore the RRP speed control UPS following corrective maintenance. Operators returned the unit to full power on the same day. On May 17, 2013, operators reduced power to approximately 76 percent RTP to support planned turbine valve testing, control rod scram time testing, and a control rod sequence exchange. Following additional planned and contingency corrective maintenance activities, operators returned the unit to full power on May 18, 2013. On June 12, 2013, operators manually scrammed the unit due to a trip of the B circulating water pump (CWP). The unit was synchronized to the grid on June 18, 2013, and returned to 100 percent power on June 19, 2013. On June 19, 2013, operators reduced power to approximately 96 percent and then 88 percent RTP after the A RRP second stage seal cavity temperature exceeded 180 °F on two occasions. Operators returned the unit to full power on June 20, 2013. On each day from June 24, 2013, through June 30, 2013, operators reduced power to as low as 94 percent power to maintain condenser vacuum. Otherwise, the unit remained at or near 100 percent power for the duration of the inspection period except for brief periods to support planned testing and rod pattern adjustments.
REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity
1R01 Adverse Weather Protection
.1 Readiness for Seasonal Extreme Weather Conditions
a. Inspection Scope
The inspectors performed a review of PSEGs readiness for the onset of seasonal high temperatures. The review focused on the emergency diesel generators (EDGs),circulating water, and station service water (SSW) systems. The inspectors reviewed the Updated Final Safety Analysis Report (UFSAR) and TSs to determine what temperatures or other seasonal weather could challenge these systems and to ensure PSEG personnel had adequately prepared for these challenges. The inspectors reviewed station procedures, including PSEGs 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 hot weather conditions. Documents reviewed for each section of this inspection report are listed in the Attachment.
b. Findings
No findings were identified.
.2 Summer Readiness of Offsite and Alternate Alternating Current (AC) Power Systems
a. Inspection Scope
The inspectors performed a review of plant features and procedures for the operation and continued availability of the offsite and alternate AC power system to evaluate readiness of the systems prior to seasonal high grid loading. The inspectors reviewed PSEGs procedures affecting these areas and the communications protocols between the transmission system operator and PSEG. This review focused on changes to the established program and material condition of offsite alternate AC power equipment.
When required, the inspectors assessed whether PSEG established and implemented appropriate procedures and protocols to monitor and maintain availability and reliability of both the offsite AC power system and the onsite alternate AC power system. The inspectors evaluated the material condition of the associated equipment by interviewing responsible PSEG personnel, reviewing the switchyard summer readiness letter, and walking down portions of the offsite and alternate AC power systems, including the main transformers and the 500 kilovolt (kV) and 13.8 kV switchyards.
b. Findings
No findings were identified.
==1R04 Equipment Alignment
Partial System Walkdowns (71111.04 - 3 samples)
a. Inspection Scope
==
The inspectors performed partial walkdowns of the following systems:
B filtration, recirculation, and ventilation system (FRVS) ventilation fan, B EDG, and 1-E switchgear and logic panels with the A FRVS ventilation fan out-of-service (OOS) for planned maintenance on April 3, 2013
B safety auxiliaries cooling system (SACS) with the A2 SACS heat exchanger (HX)
OOS for planned maintenance on May 9, 2013
HPCI and reactor core isolation cooling (RCIC) jockey pumps following an emergent failure of the feedwater (FW) line cross-tie valve on May 16, 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, work orders (WOs), condition reports (notifications), and the impact of ongoing work activities on redundant trains of equipment in order to identify conditions that could have impacted the performance of system 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. 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 CAP for resolution with the appropriate significance characterization.
b. Findings
No findings were identified.
==1R05 Fire Protection
Resident Inspector Quarterly Walkdowns (71111.05Q - 5 samples)
==
a. Inspection Scope
The inspectors conducted tours of the areas listed below to assess the material condition and operational status of fire protection features. The inspectors verified that PSEG 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 OOS, degraded, or inoperable fire protection equipment, as applicable, in accordance with procedures.
FRH-II-713, service water (SW) intake structure on May 8, 2013
FRH-II-723, motor control center (MCC) area, reactor auxiliaries cooling pumps, and HX area and safeguard instrument rooms, elevation 77 on May 22, 2013
FRH-II-531, EDG rooms on May 29, 2013
FRH-II-412, B residual heat removal (RHR) pump and HX, elevation 54 on June 27, 2013
FRH-II-551, EDG 125V battery rooms, elevation 146 on June 27, 2013
b. Findings
No findings were identified.
1R06 Flood Protection Measures
Annual Review of Cables Located in Underground Bunkers/Manholes
a. Inspection Scope
The inspectors conducted an inspection of underground bunkers/manholes subject to flooding that contain cables whose failure could affect risk-significant equipment. The inspectors performed walkdowns of risk-significant areas, including manholes MH-15MM0D08 and MH-15MM0D06, which contain risk significant offsite power cables from the switchyard to the 1AX501 and 1BX501 station power transformers, to verify that the cables were not submerged in water, that cables were intact, and to observe the condition of cable support structures. The inspectors verified proper sump pump operation and verified level alarm circuits were set in accordance with station procedures and calculations to ensure that the cables will not be submerged.
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 April 16, 2013, which included an automatic standby liquid control (SLC) system initiation, a loss of coolant accident (LOCA) sequencer inadvertent initiation, RRP high vibrations, and a small break LOCA. The inspectors evaluated operator performance during the simulated events and verified completion of critical tasks and 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 TS 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 a planned downpower and subsequent power ascension associated with resetting the A and B RRP scoop tubes and isolating the RRP speed control UPS for corrective maintenance on May 9, 2013. The inspectors also observed and reviewed a planned downpower and turbine valve testing conducted on May 17, 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 reactivity manipulations to verify that procedure use and crew communications 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 CAP documents (notifications), maintenance WOs (orders), and maintenance rule (MR) basis documents to ensure that PSEG was identifying and properly evaluating performance problems within the scope of the MR.
For each sample selected, the inspectors verified that the SSC was properly scoped into the MR in accordance with 10 Code of Federal Regulations (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 MR system boundaries.
A SLC pump discharge relief valve failed setpoint high on February 5, 2012 (Order
===70148443)
FW cross-connect valve (1AE-HV-4144) motor operator stall condition evaluation on May 9, 2013 (Order 80102654-0040)
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.
Unplanned maintenance and approved troubleshooting following the failure of the HPCI auxiliary oil pump (AOP) to start on April 8, 2013 (Notification 20602350)
Unplanned maintenance on the RRP speed control UPS on May 9, 2013 (Order 60110684)
Unplanned maintenance on the cross connect valve (HV-4144) for the FW supply lines on May 9, 2013 (Notification 20607448)
Emergent maintenance on the D SSW strainer during planned replacement of the C SSW traveling water screen on June 2, 2013 (Order 60110992)
Unplanned maintenance and approved troubleshooting on the A nuclear management and control (NUMAC) drawer on June 3, 2013 (Order 60111018)
b. Findings
No findings were identified.
1R15 Operability Determinations and Functionality Assessments
a. Inspection Scope
The inspectors reviewed operability determinations (ODs) for the following degraded or non-conforming conditions:
Safety relief valve (SRV) (F013R) high temperature alarm on January 30, 2013 (Notification 20593312)
Potential leakage through the reactor water cleanup (RWCU) drain line valves as it relates to the American Society of Mechanical Engineers (ASME) Code Class 1 pressure boundary criteria on April 18, 2013 (Notification 20602181)
Loss of power to the B EDG fuel oil storage tank level indicators on April 12, 2013 (Notification 20602818)
Degraded FW penetration sealing water system to penetrations P2A and P2B on May 9, 2013 (Order 70153980-0010)
The inspectors selected these issues based on the risk significance of the associated components and systems. The inspectors evaluated the technical adequacy of the ODs 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 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
Permanent Modifications
a. Inspection Scope
The inspectors evaluated revisions to documents that establish SACS room temperatures when no room coolers are available, as implemented by engineering change package 80108856, SACS Room Temperature without Cooling from Room Coolers, Revision 0. 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 a revision of design calculation 11-0066, Revision 8, which establishes SACS room (rooms 4307 and 4309) temperatures when all SACS room coolers are not functional and ultimate heat sink temperature is 80 degrees Fahrenheit or less. The inspectors also reviewed procedure OP-HC-108-115-1001, Operability Assessment and Equipment Control Program, Revision 26, and interviewed engineering and operations personnel to ensure the procedure could be reasonably performed.
b. Findings
No findings were identified.
1R19 Post-Maintenance Testing
a. Inspection Scope
The inspectors reviewed the post-maintenance tests (PMTs) for the maintenance activities listed below to verify that procedures and test activities ensured system operability and functional capability. The inspectors reviewed the test procedure to verify that the procedure adequately tested the safety functions that may have been affected by the maintenance activity, that the acceptance criteria in the procedure was consistent with the information in the applicable licensing basis and/or design basis documents, and that the procedure had been properly reviewed and approved. The inspectors also witnessed the test or reviewed test data to verify that the test results adequately demonstrated restoration of the affected safety functions.
D RHR pump following planned motor replacement on April 1, 2013 (Order 30173284)
A SLC alarm and indication circuit following emergent loss of squib valve continuity alarm and indication on April 1, 2013 (Order 60109525)
Reactor manual control system following repairs of an emergent system lockup condition on April 3, 2013 through April 5, 2013 (Order 60099516)
HPCI logic system functional test following emergent failure and replacement of relay 1BJYY-K056-E41A on April 8, 2013 (Order 30098689)
RCIC planned relay replacements on April 22, 2013 (Order 60109275)
B RHR system following emergent vent line repair on June 15, 2013 (Order 60111317)
C SSW pump following planned traveling water screen replacement on June 20, 2013 (Order 30174677)
b. Findings
No findings were identified.
1R20 Refueling and Other Outage Activities
a. Inspection Scope
The inspectors reviewed the stations work schedule and outage risk plan for a unit forced outage (F131), which was conducted June 12 through June 17, 2013, following a trip of the B CWP. The inspectors reviewed PSEGs development and implementation of outage plans and schedules to verify that risk, industry experience, previous site-specific problems, and defense-in-depth were considered. During the outage, the inspectors observed portions of the shutdown and cooldown processes and monitored controls associated with the following outage activities:
Configuration management, including maintenance of defense-in-depth, commensurate with the outage plan for the key safety functions and compliance with the applicable TSs when taking equipment OOS
Implementation of clearance activities and confirmation that tags were properly hung and that equipment was appropriately configured to safely support the associated work or testing
Status and configuration of electrical systems and switchyard activities to ensure that TSs were met
Monitoring of decay heat removal operations
Impact of outage work on the ability of the operators to operate the spent fuel pool cooling system
Reactor water inventory controls, including flow paths, configurations, alternative means for inventory additions, and controls to prevent inventory loss
Activities that could affect reactivity
Maintenance of secondary containment as required by TSs
Fatigue management
Tracking of startup prerequisites, walkdown of the drywell (primary containment) to verify that debris that could block the emergency core cooling system suction strainers had not been left, and startup and ascension to full power operation
Identification and resolution of problems related to forced outage activities
b. Findings
No findings were identified.
1R22 Surveillance Testing
a. Inspection Scope
The inspectors observed performance of surveillance tests and/or reviewed test data of selected risk-significant SSCs to assess whether test results satisfied TSs, the UFSAR, and 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-0004, RHR Pump (DP202) 2-year Comprehensive Pump Test on April 1, 2013 (In-service test (IST))
HC.IC-FT.BJ-0007, Logic System Functional Test, Containment High Pressure/Reactor Low Water Level/Reactor High Water Level HPCI Actuation on April 8, 2013
HC.IC-CC.SK-0004, HPCI - Division 3 Steam Leak Detection Temperature Monitor, H1SK-1SKXR-11504, on April 9, 2013
HC.OP-ST.BD-0003, RCIC Functional Verification - 18 months on April 22, 2013
HC.OP-DL.ZZ-0026, Drywell Floor Drain Leakage Monitoring and HC.CH-SA.HB-0010, Sampling the Drywell Floor Sump on May 1, 2013 (reactor coolant system (RCS) leakage)
HC.OP-IS.BH-0004(Q), SLC Pump-BP208 - IST on June 11, 2013 (IST)
b. Findings
No findings were identified.
Cornerstone: Emergency Preparedness
1EP6 Drill Evaluation
Training Observations
a. Inspection Scope
The inspectors observed a simulator training evolution for licensed operators on May 6, 2013, which required emergency plan implementation by an operations crew.
PSEG planned for this evolution to be evaluated and included in performance indicator (PI) data regarding drill and exercise performance. The inspectors observed event classification and notification activities performed by the crew. The inspectors also attended the post-evolution critique for the scenario. The focus of the inspectors activities was to note any weaknesses and deficiencies in the crews performance and ensure that PSEG evaluators noted the same issues and entered them into the CAP.
b. Findings
No findings were identified.
RADIATION SAFETY
Cornerstone: Public Radiation Safety
2RS5 Radiation Monitoring Instrumentation
From May 20 to 24, 2013, the inspectors reviewed the accuracy and operability of radiation monitoring instruments. The review was based on 10 CFR 20, 10 CFR 50, 40 CFR 190, applicable regulatory guides (RGs) and industry standards, the TSs and Offsite Dose Calculation Manual (ODCM), and PSEG procedures for determining compliance.
a. Inspection Scope
Inspection Planning
The inspectors reviewed the UFSAR to identify radiation instruments associated with monitoring airborne radioactivity, process streams, and radioactive effluents.
Additionally, the inspectors selectively reviewed the associated TS requirements for post-accident monitoring instrumentation.
The inspectors reviewed available third-party evaluation reports of the radiation monitoring program since the last inspection.
The inspectors reviewed effluent monitor alarm setpoints and the calculation methods provided in the ODCM.
Walkdowns and Observations The inspectors walked down two gaseous effluent radiation monitoring systems. The inspectors assessed whether the effluent/process monitor configurations align with the UFSAR and ODCM specifications.
Calibration and Check Sources
The inspectors reviewed PSEGs waste stream characterization per 10 CFR 61, Licensing Requirements for Land Disposal of Radioactive Waste, to assess the types and energies of radiation encountered in the plant.
Problem Identification and Resolution The inspectors evaluated whether problems associated with radiation monitoring instrumentation were being identified by PSEG at an appropriate threshold and were properly addressed for resolution in Hope Creeks CAP. The inspectors assessed the appropriateness of the corrective actions for a sample of problems documented by Hope Creek that involve radiation monitoring instrumentation.
b. Findings
No findings were identified.
2RS6 Radioactive Gaseous and Liquid Effluent Treatment
From May 20 to May 24, 2013, the inspectors verified that gaseous and liquid effluent processing systems were maintained so radiological discharges were properly reduced, monitored, and released. The inspectors also verified the accuracy of calculations for effluent release and public dose.
The inspectors used the requirements in 10 CFR 20, Standards for Protection Against Radiation; 10 CFR 50.36, TSs; 10 CFR 50, Appendix A, Criterion 60, Control of Releases of Radioactive Materials to the Environment, and Criterion 64, Monitoring Radioactivity Releases; 10 CFR 50, Appendix I, Numerical Guides for Design Objectives and Limiting Conditions for Operation 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; RG 1.109, Calculation of Annual Doses to Man from Routine Releases of Reactor Effluents for the Purpose of Evaluating Compliance with 10 CFR 50, Appendix I; RG 1.21, Measuring, Evaluating, and Reporting Radioactive Material in Liquid and Gaseous Effluents and Solid Waste; RG 4.1, Radiological Environmental Monitoring for Nuclear Power Plants; RG 4.15, Quality Assurance for Radiological Monitoring Programs; NUREG 1301, ODCM Guidance: Standard Radiological Effluent Controls for Pressurized Water Reactors; applicable industry standards; and licensee procedures required by the TSs and ODCM as criteria for determining compliance.
a. Inspection Scope
Event Report and Effluent Report Reviews The inspectors reviewed the Hope Creek Station 2012 Radioactive Effluent Release Report and Radiological Environmental Monitoring Report to determine if the reports were submitted as required by the TSs and ODCM. The inspectors reviewed anomalous results, unexpected trends, and abnormal releases that were identified. The inspectors determined if these effluent results were evaluated, were entered in the CAP, and were adequately resolved.
The inspectors identified and reviewed radioactive effluent monitor operability issues to determine if the issues were entered into the CAP and adequately resolved.
ODCM and UFSAR Review The inspectors reviewed UFSAR descriptions of the radioactive effluent monitoring systems, treatment systems, and effluent flow paths to identify system design features and required functions.
The inspectors reviewed changes to the ODCM made since the last inspection. When differences were identified, the inspectors reviewed the technical basis or evaluations of the change and determined whether they were technically justified and maintained effluent releases ALARA.
The inspectors reviewed documentation to determine if any non-radioactive systems that have become contaminated were either disclosed through an event report or the ODCM.
The inspectors reviewed 10 CFR 50.59 evaluations and made a determination if any newly contaminated systems had an unmonitored effluent discharge path to the environment. The inspectors also reviewed whether required revisions to the ODCM were made to incorporate new public dose pathways.
Groundwater Protection Initiative (GPI) Program The inspectors reviewed reported groundwater monitoring results and changes to Hope Creeks written program for identifying and controlling contaminated spills/leaks to groundwater.
Procedures, Special Reports, and Other Documents The inspectors reviewed available event reports and/or special reports related to the effluent program issued since the previous inspection to identify any additional focus areas for the inspection based on the scope/breadth of problems described in these reports.
The inspectors reviewed effluent program implementing procedures, including those associated with effluent sampling, effluent monitor setpoint determinations, and dose calculations.
The inspectors reviewed copies of Hope Creek Station and third party evaluation reports of the effluent monitoring program since the last inspection to gather insights into the effectiveness of the program.
Walkdowns and Observations The inspectors walked down components of the north and south plant vent gaseous discharge systems to verify equipment configuration and flow paths. During walkdowns, special attention was made to identify potential unmonitored release points, building alterations that could impact airborne or liquid effluent controls, and ventilation system leakage that communicates directly with the environment.
The inspectors reviewed effluent system material condition surveillance records for equipment or areas associated with the systems selected for review that were not readily accessible due to radiological conditions.
The inspectors walked down filtered ventilation systems to verify there were no degraded conditions associated with high-efficiency particulate air/charcoal banks, improper alignment, or system installation issues that would impact the performance or effluent monitoring capability of the effluent system.
The inspectors observed portions of the routine processing and discharge of radioactive gaseous effluent to verify that appropriate treatment equipment was used and that processing activities align with discharge permits. The inspectors verified selected gaseous and liquid dose projection calculations.
The inspectors reviewed if there have been any changes to the Hope Creek effluent release paths. The inspectors verified that appropriate effluent treatment equipment was being used for discharges.
Sampling and Analyses The inspectors selected three effluent sampling activities (two gaseous and one liquid)and assessed whether adequate controls have been implemented to ensure representative samples were obtained.
The inspectors reviewed effluent discharges with inoperable effluent radiation monitors to verify that controls were in place to ensure compensatory sampling was performed and that controls were adequate to prevent the release of unmonitored liquid and gaseous effluents.
The inspectors determined whether the facility is routinely relying on the use of compensatory sampling in lieu of adequate system maintenance, based on the frequency of compensatory sampling since the last inspection.
The inspectors reviewed the results of the inter-laboratory and intra-laboratory comparison program to verify the quality of the radioactive effluent sample analyses.
The inspectors also assessed whether the intra-and inter-laboratory comparison program included hard-to-detect isotopes, as appropriate.
Effluent Flow Measuring Instruments The inspectors reviewed the methodology that PSEG uses to determine the flow rates of the north and south plant vent and filter recirculation vent to verify that the flow rates were consistent with the TSs, ODCM, and FSAR values. The inspectors reviewed the differences between assumed and actual flow rates to ensure that they do not affect the calculated results of public dose.
Air Cleaning Systems The inspectors assessed whether surveillance test results for ventilation effluent discharge systems met acceptance criteria.
Dose Calculations The inspectors reviewed all significant changes in reported dose values compared to the previous radioactive effluent release report to evaluate the factors that may have resulted in any changes.
The inspectors reviewed one radioactive liquid and one gaseous waste discharge permit to verify that the projected doses to members of the public were accurate and based on representative samples of the discharge path.
The inspectors evaluated the methods used to ensure that representative radionuclides in the effluent stream source term were included. The review included the current waste stream analyses to ensure hard-to-detect radionuclides were included in the releases.
The inspectors reviewed changes in offsite dose calculation methodology since the last inspection to verify the changes are consistent with requirements. The inspectors reviewed meteorological dispersion and deposition factors used in the ODCM and effluent dose calculations to ensure appropriate dispersion/deposition factors are being used for public dose calculations.
The inspectors reviewed the latest land use census to verify changes that affect public dose pathways have been factored into the dose calculations and environmental sampling/analysis program.
The inspectors evaluated whether the calculated doses were within the 10 CFR 50, Appendix I and TS dose criteria.
The inspectors reviewed records of abnormal gaseous or liquid tank discharges to ensure the abnormal discharges were monitored by the discharge point effluent monitor.
Discharges made with inoperable effluent radiation monitors, or unmonitored leakages were reviewed to ensure that these discharges were evaluated to account for the effluent releases and that they were included in the report of calculated public doses.
GPI Implementation The inspectors reviewed implementation and monitoring results of the voluntary Nuclear Energy Institute (NEI) GPI. For anomalous results or missed samples, the inspectors assessed whether PSEG identified and addressed deficiencies through its CAP.
The inspectors discussed identified leakage or spill events and associated documentation in PSEG decommissioning files. The inspectors reviewed evaluations of leaks or spills, and reviewed the effectiveness of remediation actions. The inspectors reviewed onsite contamination events involving contamination of groundwater and assessed whether the source of the leak or spill was identified and isolated/terminated.
The inspectors assessed whether an evaluation was performed to determine the type and amount of radioactive material that was discharged. The inspectors assessed whether sufficient radiological surveys were performed to evaluate the extent of the contamination, assessed whether adequate evaluations were performed, and determined whether PSEG completed offsite notifications, as provided in its GPI implementing procedures.
The inspectors reviewed the evaluation of discharges from onsite surface water bodies that contain radioactivity and the potential for groundwater leakage from these onsite surface water bodies. The inspectors assessed whether PSEG was properly accounting for discharges from these surface water bodies as part of their effluent release reports.
The inspectors assessed whether on-site groundwater sample results and a description of any significant on-site leaks/spills into groundwater for each calendar year were documented in applicable reports.
For significant new effluent discharge points the inspectors evaluated whether the Hope Creek ODCM was updated to include the dose calculation method for the new release point and the associated dose calculation methodology.
b. Findings
No findings were identified.
OTHER ACTIVITIES
4OA1 Performance Indicator Verification
RCS Specific Activity and RCS Leak Rate===
a. Inspection Scope
The inspectors reviewed PSEGs submittal for the RCS specific activity and RCS leak rate PIs for the period of July 1, 2012, through March 31, 2013. To determine the accuracy of the PI data reported during those periods, the inspectors used definitions and guidance contained in NEI Document 99-02, Regulatory Assessment PI Guideline, Revision 6. The inspectors also reviewed RCS sample analysis and control room logs of daily measurements of RCS leakage and compared that information to the data reported by the performance indicator. Additionally, the inspectors observed surveillance activities that determined the RCS identified leakage rate.
b. Findings
No findings were identified.
4OA2 Problem Identification and Resolution
.1 Routine Review of Problem Identification and Resolution Activities
a. Inspection Scope
As required by Inspection Procedure (IP) 71152, Problem Identification and Resolution (PI&R), the inspectors routinely reviewed issues during baseline inspection activities and plant status reviews to verify that PSEG 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 notification screening meetings.
b. Findings
No findings were identified.
.2 Semi-Annual Trend Review
a. Inspection Scope
The inspectors performed a semi-annual review of site issues, as required by IP 71152, PI&R, 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 PSEG outside of the CAP, such as trend reports, PIs, major equipment problem lists, system health reports, MR assessments, and maintenance or CAP backlogs. The inspection also reviewed PSEGs CAP database for the period from December 2012 to May 2013 to assess notifications written and individual issues identified during NRCs daily notification review. The inspectors reviewed the Hope Creek performance improvement integrated matrix (PIIM) for the first cycle of 2013, conducted under procedure LS-AA-125-1006, PIIM to verify that PSEG personnel were appropriately evaluating and trending adverse conditions in accordance with applicable procedures.
b. Findings and Observations
No findings were identified.
Engineering trends overall equipment reliability using procedure ER-AA-2200, Equipment Reliability Performance Objectives and Criteria Bubble Chart
Analysis.
The inspectors reviewed the most current engineering bubble chart. PSEG also performs a low level trending analysis using Pareto methods. The inspectors reviewed the Pareto analysis for the six-month period ending in March 2013 and Notification 20599573 generated to document a trend in one aspect of human performance.
The inspectors reviewed notifications issued during the six months in question and evaluated licensee corrective actions for performance issues in the following areas based on that review: 1) the reliability of fire alarms and the response to such alarms in high radiation areas; 2) the unavailability of local power range monitors (LPRMs); and 3)the implementation of the MR in response to an observation made during the most recent biennial PI&R team inspection.
The inspectors noted in the previous semi-annual trend review an increasing trend in the number of spurious fire alarms in various locations of the protected area. On April 19, 2013, an Unusual Event (UE) was declared due to a fire alarm spuriously actuating in a locked high radiation area (LHRA). The operations staff that responded could not reach the area and obtain key access to this area within 15 minutes of the time the alarm came in, prompting the UE declaration. As a corrective action, PSEG installed cameras in all LHRAs with fire detection equipment to allow prompt verification of the existence or absence of a fire. PSEG is also developing a PM task to clean the detectors and evaluating replacing the system because of obsolescence.
The inspectors also reviewed a common cause evaluation (CCE) for the number of LPRM failures during the last outage and the current operating cycle. The number of unavailable LPRMs had been declining for a number of years but began increasing in 2008. A CCE was performed, which identified several distinct causes for problems with the LPRM that forced them to be bypassed. In response, PSEG initiated six condition report corrective actions (CRCAs) and action tracking items (ACITs) to address the common causes identified. The inspectors discussed the progress of these corrective actions with the responsible system engineer, verified that the number of OOS LPRMs declined since the CCE was initiated, and reviewed the OOS LPRM repair and replacement plan for the next refueling outage.
Finally, the inspectors reviewed a performance improvement action plan developed to improve the implementation of the MR based on inconsistencies identified by the NRC and PSEGs Nuclear Oversight organization. The evaluation performed as part of the performance improvement plan identified performance issues consistent with the observation in the NRCs 2013 PI&R team inspection. The inspectors reviewed the CRCA and the two implemented ACITs to improve implementation of the MR.
Based on the overall review of the selected sample, the inspectors concluded that PSEG was appropriately identifying and entering issues into the CAP, adequately evaluating the identified issues, and appropriately identifying adverse trends before they become more significant safety concerns.
.3 Annual Sample:
Average Power Range Monitor (APRM) Trip Point Settings For Single Loop Operation
a. Inspection Scope
The inspectors performed an in-depth review of PSEGs apparent cause analysis and corrective actions associated with Licensee Event Report (LER) 50-354/2012-01, APRM Flow Unit Summers Out of TS Tolerance, and Notification 20549760. This issue was discussed in NRC Integrated Inspection Report 05000354/2012003 as Green NCV 05000354/2012003-02. Specifically, on March 4, 2012, during APRM flow unit summer weekly calibration with the unit in single loop operation, reactor recirculation drive flow was incorrectly calculated, which resulted in an improper trip setpoint being calculated and inserted. As a result, all four APRM flow unit summers were out of tolerance for a period of time greater than permitted by TSs.
The inspectors assessed PSEGs problem identification threshold, cause analyses, extent of condition reviews, compensatory actions, and the prioritization and timeliness of PSEGs corrective actions to determine whether PSEG was appropriately identifying, characterizing, and correcting problems associated with this issue and to determine whether the planned or completed corrective actions were appropriate. The inspectors compared the actions taken to the requirements of PSEGs CAP and 10 CFR 50, Appendix B.
b. Findings and Observations
No findings were identified.
PSEG determined the most probable cause was that the calibration of the APRM flow unit summers during single loop operation was not covered by procedural guidance.
PSEG also determined that ambiguous instructions in the procedures, which did exist, resulted in calculation of an inaccurate drive flow.
PSEG conducted a thorough technical review of the TS requirements for instrumentation during single loop operation. PSEGs extent of condition review identified that instrumentation and controls (I&C) and reactor engineering personnel were unfamiliar with the determination of recirculation drive flow during single loop operation. Corrective actions included revising reactor engineering procedures to provide instructions for calculating drive flow during single loop operation, and revising I&C procedures for adjusting instruments when transitioning into and out of single loop operation. The inspectors determined PSEGs overall response to the issue was commensurate with the safety significance, was timely, and included appropriate corrective actions. The inspectors determined that the actions taken were reasonable to resolve the issues of instrument calibration during single loop operation.
.4 Annual Sample:
Bailey 862 Solid State Logic Module (SSLM) Replacement Program
a. Inspection Scope
The inspectors performed an in-depth review of PSEGs apparent cause analysis and corrective actions associated with Notification 20577641, Failure in AC653 leads to A Reactor Feed Pump (RFP) Trip. On September 30, 2012, during a plant transient involving a runback of the RRPs, operators noted that the A RFP was tripped without the associated overhead annunciator alarming. The annunciator alarmed several minutes after the RFP tripped. Control room integrated display points associated with the RFP trip came in twice during the transient, approximately 4 minutes apart. Reviews determined that all the indications originated in the H1RL-1A-C-653 panel of the Bailey 862 control system.
The inspectors assessed PSEGs problem identification threshold, cause analyses, extent of condition reviews, compensatory actions, and the prioritization and timeliness of PSEGs corrective actions to determine whether PSEG was appropriately identifying, characterizing, and correcting problems associated with this issue and whether the planned or completed corrective actions were appropriate. The inspectors compared the actions taken to the requirements of PSEGs CAP and 10 CFR 50, Appendix B.
b. Findings and Observations
No findings were identified.
PSEG determined the cause of the event was an intermittent loss of the operate bus for cabinet 8 of the AC653 panel. The apparent cause of the loss of the operate bus was a failed optical isolator on input one of H1RL-1RLXIS-AC653080202. PSEG replaced the failed SSLM card and completed required testing within the TS allowed outage time.
PSEG conducted a thorough review of the circumstances surrounding the failure and determined that the potential risk of the cards failure had been previously evaluated under Order 70110566-0250. PSEG determined that the card had been correctly classified as medium risk and appropriately scheduled for replacement under Maintenance Order 60101055. An extent of condition review determined that there are 225 more SSLMs supporting critical components that have not yet been replaced under the Bailey Logic Module Replacement Project. Those remaining modules are currently scheduled for replacement during the next refueling outage.
The inspectors determined PSEGs overall response to the issue was commensurate with the safety significance, was timely, and included appropriate corrective actions.
The inspectors determined that the actions taken were reasonable to resolve the issue of Bailey SSLM failures.
4OA3 Follow-Up of Events and Notices of Enforcement Discretion
.1 Plant Events
a. Inspection Scope
For the plant events listed below, the inspectors reviewed and/or observed plant parameters, reviewed personnel performance, and evaluated performance of mitigating systems. The inspectors communicated the plant events to appropriate regional personnel, and compared the event details with criteria contained in IMC 0309, Reactive Inspection Decision Basis for Reactors, for consideration of potential reactive inspection activities. As applicable, the inspectors verified that PSEG made appropriate emergency classification assessments and properly reported the event in accordance with 10 CFR Parts 50.72 and 50.73. The inspectors reviewed PSEGs follow-up actions related to the events to assure that PSEG implemented appropriate corrective actions commensurate with their safety significance.
Loss of emergency notification system telephone (Event Notifications (ENs) 48905 and 48908)
UE declared on April 19 due to inability to confirm a fire alarm in the protected area within 15 minutes (EN 48947)
CWP trip leads to a reactor scram (EN 49108) and subsequent discovery of pressure boundary leakage on June 12 (EN 49110)
b. Findings
No findings were identified.
.2 (Closed) LER 2013-001-00:
High Pressure Coolant Injection System Inoperable Due to Control Relay Failure
During the performance of HC.IC-FT.BJ-0007, "Logic System Function Test - Containment High Pressure/Low Water Level/Reactor High Water Level HPCI Actuation" on April 8, 2013, the operator noted that the HPCI Stop Valve (FV-4880) did not open as expected and the operator observed that the HCPI AOP failed to start. The shift manager entered the action statement for TS 3.5.1 and declared the HPCI system inoperable. Preliminary investigation showed that a normally de-energized control relay (1 BJYY-K056-E41A) had failed. This relay was replaced and operability restored on April 8, 2013. The HPCI system was declared inoperable because of the failure of a control relay, which prevented the HPCI AOP from automatically starting on demand.
This condition is reportable under 10 CFR 50.73(a)(2)(v)(D) for a condition that could have prevented fulfillment of a safety function of structures or systems that are needed to mitigate the consequences of an accident. The inspectors performed an in-depth review of this LER 50-354/2013-001-00 and PSEGs apparent cause analysis associated with notifications 20602350 and 20602498. During the review of this LER, the inspectors identified one issue that is discussed below. This LER is closed.
b. Findings
Introduction.
A self-revealing Green NCV of TS 6.8.1, Procedures, was identified because PSEG failed to establish an appropriate PM schedule for Tyco/Agastat GP control relays. Specifically, an evaluation PSEG performed to revise HPCI relay replacement periodicities from 22 years to 40 years neither adequately addressed available relay references nor all applicable failure mechanisms; as a result, HPCI failed to respond to logic system actuation signals during surveillance testing on April 8, 2013.
Description.
On April 8, 2013, the HPCI system was declared inoperable during the performance of HC.IC-FT.BJ-0007, "Logic System Function Test - Containment High Pressure/Low Water Level/Reactor High Water Level HPCI Actuation," Revision 12.
During the test, I&C technicians inserted a reactor low water level initiation (Level 2)signal to initiate a start of the HPCI AOP. The operator noted that the HPCI stop valve (FV-4880) did not open as expected and observed that the HCPI AOP failed to start.
Upon recognizing the HPCI AOP failure to start, operators declared the HPCI system inoperable. Troubleshooting identified that the HPCI AOP control relay (1 BJYY-K056-E41A), a normally de-energized relay, had failed. The relay was replaced, and the HPCI AOP start signal was successfully retested. Hope Creek determined that, in spite of the failure to respond to an automatic actuation signal, HPCI was capable of being manually started, because the failed relay was not part of the manual start circuitry.
In a related event on April 9, 2013, during the performance of HC.IC-CC.SK-0004(Q),
HPCI - Division 3 Steam Leak Detection Temperature Monitoring H1SK-1SKXR-11504, Revision 13, the relay that provides the close signal to the HPCI turbine inboard isolation valve (HV-F002) had a resistance of 47 ohms with a closed contact; the relay was expected to have a resistance of less than 1 ohm with a closed contact. Upon recognizing the HV-F002 failure, operators declared the HPCI system inoperable. The relay was subsequently replaced because of the high resistance and successfully retested. Upon further inspection, all contact surfaces were verified to be properly engaging and not air-gapped, but all eight contacts were found to have high resistances, and two of the normally open contacts resistances were high enough to cause open circuits. Additional analysis revealed that all of the failed contacts had phosphorus deposits on their respective surfaces that caused the excessive resistance values.
Both of the failed relays were manufactured in 1980 and were installed in the station prior to initial plant startup in 1986. The relay vendor, Tyco, guarantees the relays for 25,000 cycles or ten years. The relays were only cycled a few times each year and had margin to the 25,000 cycle limit. However, the relays were in-service well beyond the vendors recommended 10 year qualified life (33 years). Both relay failure mechanisms identified by Hope Creek - an open coil caused by corrosion on one relay, and high contact resistance on the second relay - are considered age-related failure mechanisms.
As part of the Hope Creek AGASTAT Relay PM program in 2003, 22-year periodic replacement frequency PM activities were created for the two subject failed relays. In 2007, a population of normally de-energized Agastat GP control relays was reviewed to remove conservatism in the replacement periodicity. The review determined that the replacement periodicity could be revised from 22 years to 40 years. This new periodicity for the Agastat GP control relays was based on calculation, their type, qualification, and failure history.
The PM change procedure in place in 2007, Attachment 4 of NC.ER-DG.ZZ-0100(Z),
Equipment Reliability Analysis, Revision 3, included reference documents that were to be reviewed as part of the PM change evaluation. Contrary to this procedural requirement, PM change evaluations did not show that the specified relay references such as Electric Power Research Institute Technical Report, TR-102067, Maintenance and Application Guide for Control Relays and Timers, issued December 1993, were reviewed by the station. Consequently, not all applicable failure mechanisms, such as relay coil burnout, high contact resistance, mechanical binding, and lead failure were considered. Additionally, at the time the PM changes were implemented, there was no governing body for the PM program, the PM program coordinator was an administrative position with no enforcement or oversight function, and engineering supervisors had approval authority for PM changes.
PSEGs immediate corrective actions included replacing the failed relays. Additionally, PSEG plans to revise the replacement frequency and to replace other Tyco/Agastat GP control relays of high safety significance, as identified in their extent of condition review.
PSEG entered this issue into its CAP as notifications 20602350 and 20602498.
Analysis.
The inspectors determined that the failure to establish an appropriate PM schedule for Tyco/Agastat GP control relays was a performance deficiency that was within PSEGs ability to foresee and correct, and should have been prevented.
Specifically, the PM change evaluations conducted in 2007 did not review the relay references specified in NC.ER-DG-ZZ-0100(Z), Equipment Reliability Analysis, and did not consider all applicable failure mechanisms. This finding was more than minor because it is associated with the equipment performance attribute of the mitigating systems cornerstone and affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the failure of these relays caused the automatic start capability of the HPCI system to be unavailable and caused unplanned inoperability of the HPCI system. The inspectors evaluated the finding using the Phase 1, Initial Characterization of Findings, worksheet in Attachment 4 to IMC 0609, Significance Determination Process, issued June 2, 2011, which instructs the inspectors to utilize IMC 0609 Appendix A, The SDP for Findings At-Power, issued June 19, 2012.
Evaluating the finding using Exhibit 2 of IMC 0609, the inspectors determined a detailed risk evaluation was needed, based upon the conservative assumption that the failure of HPCI to automatically start was a loss of safety function. The inspectors noted that although the licensee declared the HPCI system inoperable, HPCI remained available via operator recovery actions. Control room operators could have readily placed HPCI in service via manually starting the system from the control room.
The Region I Senior Reactor Analyst (SRA) used SAPHIRE and the Standardized Plant Analysis Report (SPAR) for Hope Creek to evaluate the risk significance of this issue.
The SRA made the following modeling assumptions:
Basic Event (HCI-TDP-TRAIN) Failure To Start was set to True to represent the failure of the HPCI system to respond to an automatic start signal
The unavailability time (exposure time period) used was T/2, representing one half of the time between the last successful start of the HPCI system and the discovery of the failed relay and failure to start on April 8, 2013, T/2 = 165 days
The truncation value used in the analysis was set at 1E-13
Operator recovery credit was assigned a value of 1E-2 (one in 100 chance of failure) based upon readily available procedures (alarm response cards),operator training, and the simplicity of the operator actions to manually initiate the HPCI system.
Based upon the above modeling assumptions, the change in core damage frequency (delta CDF) of the failure of the HPCI system to respond to an automatic start signal due to the logic circuit relay failure was in the high E-8 range. The dominant core damage sequences involved the loss of condenser heat sink and loss of offsite power initiating events followed by the failure of operators to recover HPCI, failure of the RCIC system, and operator failure to depressurize the RCS to permit low pressure injection.
The SRA reviewed PSEGs risk assessment, which favorably compared to the SPAR results. The licensees risk assessment identified a mid-E-7 delta CDF. PSEGs risk assessment reflected both internal and external risk contributions. The internal event dominant core damage sequences were similar to the SPAR model results. External event contributions were dominated by fires warranting control room abandonment.
Based upon the SPAR model results and similar, but independently derived licensee risk assessment results, this self-revealing performance deficiency was determined to be of very low safety significance (Green).
No cross-cutting aspect was assigned to this finding because PSEGs evaluation of the PM relay replacement periodicity was completed more than 3 years ago, and since the 2007 evaluation, a PM Ownership Committee has been created to review PM change evaluations to enforce evaluation format and level of technical rigor specified in the current PM change process, MA-AA-716-210-1005, Predefine Change Process. This performance deficiency is thereby not reflective of current plant performance.
Enforcement.
TS 6.8.1 states, in part, that written procedures recommended in Appendix A of RG 1.33, Quality Assurance Program Requirements (Operation),
Revision 2, February 1978, shall be established, implemented, and maintained. Section 9.b of Appendix A to RG 1.33 states, in part, that PM schedules should be developed to specify replacement of parts that have a specific service life. Contrary to the above, since 2007, PSEGs PM schedules for normally de-energized Tyco/Agastat GP control relays were inadequate and resulted in a failure of the HPCI logic system to respond to actuation signals during surveillance testing on April 8, 2013. Specifically, HPCI relay replacement periodicities were extended from 22 years to 40 years without adequately addressing available relay references or all applicable failure mechanisms. PSEGs immediate corrective actions included replacing failed relays. Additionally, PSEG plans to revise the replacement frequency and to replace other Tyco/Agastat GP control relays of high safety significance, as identified in their extent of condition review. Because this violation was determined to be of very low safety significance (Green), and PSEG entered this issue into its CAP as notifications 20602350 and 20602498, this violation is being treated as an NCV consistent with Section 2.3.2 of the Enforcement Policy. (NCV 05000354/2013003-01, Inadequate Preventive Maintenance Replacement Schedule for Agastat Control Relays)
4OA5 Other Activities
.1 Institute of Nuclear Power Operations (INPO) Report Review
a. Inspection Scope
The inspectors reviewed the final report for the INPO plant assessment of Hope Creek conducted in June 2012. The inspectors also reviewed the final report for the INPO accreditation team evaluation of the maintenance, engineering, chemistry, and radiological protection technical training programs conducted in March 2013. The inspectors evaluated these reports to ensure that NRC perspectives of PSEG performance were consistent with any issues identified during the assessments. The inspectors also reviewed these reports to determine whether INPO identified any significant safety issues that required further NRC follow-up.
b. Findings
No findings were identified.
.2 Operation of an Independent Spent Fuel Storage Installation (ISFSI) at Operating Plants
(60855 and 60855.1)
a. Inspection Scope
From June 10 to June 14, 2013, the inspectors observed and evaluated PSEGs loading of a multi-purpose canister (MPC) associated with PSEGs current ISFSI dry cask campaign. The inspectors also reviewed PSEGs activities related to long-term operation and monitoring of their ISFSI. The inspectors verified compliance with the Certificate of Compliance (CoC), TSs, regulations, and licensee procedures.
The inspectors observed the MPC inside the transfer cask (HI-TRAC) being moved into the cask pit, the loading of spent fuel assemblies into the MPC, and the MPC/HI-TRAC being moved from the cask pit to the cask washdown area. Inspectors observed cask processing operations including: welding of the lid to the MPC, hydrostatic testing, non-destructive examination of the lid weld, and forced helium dehydration of the MPC.
During performance of these activities the inspectors evaluated PSEGs familiarity with procedures, supervisory oversight, and communication and coordination between the personnel involved. The inspectors attended licensee briefings to assess their ability to identify critical steps of the evolution, potential failure scenarios, and human performance tools to prevent errors. The inspectors also reviewed loading and monitoring procedures and evaluated PSEGs adherence to these procedures.
NRC staff reviewed the methodology, assumptions, acceptance criteria, analysis, and results of Holtec Report No. HI-2125352, Freestanding Stack-Up Analysis in Reactor Building Floor El 102' at HCGS, to assess the response of the HI-TRAC and HI-STORM when in a freestanding stack-up configuration during a design basis seismic event.
The inspectors reviewed PSEGs program associated with fuel characterization and selection for storage. The inspectors reviewed cask fuel selection packages to verify that PSEG was loading fuel in accordance with the CoC and TSs. The inspectors confirmed that PSEG 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 PSEGs radiological controls to ensure radiation worker doses were ALARA, and to ensure 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 surface were as expected.
The inspectors performed tours 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 that PSEG was appropriately performing daily HI-STORM 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 inspectors confirmed that vehicle entry onto the ISFSI pad was controlled in accordance with the licensees procedures. 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 PSEGs 10 CFR 72.48 screenings to verify that PSEG 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 notifications, audit reports, and self-assessments that were generated since PSEGs 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.
4OA6 Meetings, Including Exit
On July 18, 2013, the inspectors presented the inspection results to Mr. E. Carr, Plant Manager of Hope Creek, 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
- P. Davison, Site Vice President
- E. Carr, Plant Manager
- D. Bartlett, Manager, System Engineering
- B. Boesch, Hope Creek Training Manager
- P. Bonnett, Regulatory Assurance
- B. Burgio, Probabilistic Risk Assessment (PRA) Engineer
- D. Bush, System Engineer
- J. Carlin, Fire Protection Superintendent
- E. Casuli, Plant Engineering Manager
- R. Chan, Manager, Nuclear Oversight
- S. Connelly, System Engineering
- B. Daly, Manager, Sustainability, Environmental Affairs
- M. Fleming, Chemistry Superintendent
- R. Ficarra, Operations
- T. Fowler, Operations Training Manager
- C. Garver, Operations Shift Supervisor
- Z. Horvath, Chemistry Technician
- M. Jermusyk, Operations Shift Supervisor
- J. Kandasamy, Work Management Director
- J. Kepley, Simulator Training Instructor
- R. Kitchengs, Work Week Manager
- K. Knaide, Engineering Director
- W. Kopchick, Operations Director
- P. Koppel, Maintenance Superintendent
- E. Martin, Senior Nuclear Engineer
- V. McPherson, Maintenance Superintendent
- M. Meltzer, Chemistry
- F. Mooney, Maintenance Director
- T. Morin, Regulatory Assurance
- J. Morris, Chemistry Technician
- L. Myers, Operations Shift Supervisor
- C. Neely, Director, Regulatory Affairs
- J. Pantaze, Manager, Environmental Affairs
- K. Powell, Fire Protection Supervisor
- J. Price, Supervisor, Chemistry
- M. Reed, Manager, Nuclear Shift Operations
- J. Russell, Principal Environmental Specialist
- S. Simpson, Regulatory Assurance Manager
- R. Smith, System Engineer
- G. Stith, Manager, Design Engineering
- H. Trimble, Radiation Protection Manager
Others
- J. Vouglitois, Nuclear Engineer, New Jersey Department of Environmental Protection, Bureau of
Nuclear Engineering
LIST OF ITEMS OPENED, CLOSED, DISCUSSED, AND UPDATED
Opened/Closed
- 05000354/2013003-01 NCV Inadequate Preventive Maintenance Replacement Schedule for Agastat Control Relays (Section 4OA3.2)
Opened
None
Closed
- 05000354/2013-001-00 LER High Pressure Coolant Injection System Inoperable due to Control Relay Failure (Section 4OA3.2)