IR 05000354/2008004
| ML083170263 | |
| Person / Time | |
|---|---|
| Site: | Hope Creek  |
| Issue date: | 11/12/2008 |
| From: | Arthur Burritt Reactor Projects Branch 3 |
| To: | Joyce T Public Service Enterprise Group |
| Burritt A RGN-I/DRP/PB3/610-337-5069 | |
| References | |
| IR-08-004 | |
| Download: ML083170263 (31) | |
Text
ber 12, 2008
SUBJECT:
HOPE CREEK GENERATING STATION - NRC INTEGRATED INSPECTION REPORT 05000354/2008004
Dear Mr. Joyce:
On September 30, 2008, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at the Hope Creek Generating Station. The enclosed integrated inspection report documents the inspection results discussed on October 15, 2008, with Mr. George Barnes and other members of your staff.
The inspections examined activities conducted under your license as they relate to safety and compliance with the Commissions rules and regulations and with the conditions of your license.
The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.
The report documents one self-revealing finding of very low safety significance (Green) that was also 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 this finding as a non-cited violation (NCV) consistent with Section VI.A.1 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 the Hope Creek Generating Station.
In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRC's document system (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
Sincerely,
/RA by Leonard Cline Acting for/
Arthur L. Burritt, Chief Projects Branch 3 Division of Reactor Projects Docket No: 50-354 License No: NPF-57 Enclosure: Inspection Report 05000354/2008004 w/Attachment: Supplemental Information cc w/encl:
W. Levis, President and Chief Operating Officer, PSEG Power G. Barnes, Site Vice President P. Davison, Director, Nuclear Oversight E. Johnson, Director of Finance J. Perry, Plant Manager, Hope Creek J. Keenan, General Solicitor, PSEG M. Wetterhahn, Esquire, Winston and Strawn, LLP Consumer Advocate, Office of Consumer Advocate, Commonwealth of PA L. Peterson, Chief of Police and Emergency Management Coordinator P. Baldauf, Assistant Director, NJ Radiation Protection Programs P. Mulligan, Chief, NJ Bureau of Nuclear Engineering
SUBJECT:
HOPE CREEK GENERATING STATION - NRC INTEGRATED INSPECTION REPORT 05000354/2008004
Dear M
SUMMARY OF FINDINGS
IR 05000354/2008004; 07/01/2008 - 09/30/2008; Hope Creek Generating Station; Post-
Maintenance Testing.
The report covered a three-month period of inspection by resident inspectors and announced inspections by regional reactor inspectors and regional health physics specialists. One Green non-cited violation (NCV) was identified. The significance of most findings is indicated by their color (Green, White, Yellow, or Red) using Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP). Findings for which the SDP does not apply may be Green or be assigned a severity level after NRC management review. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 4, dated December 2006.
NRC-Identified and Self-Revealing Findings
Cornerstone: Initiating Events
- Green.
A self-revealing, non-cited violation of Technical Specification 6.8.1,
Procedures and Programs, was identified because, during performance of post-modification testing for the high pressure coolant injection (HPCI) feedwater injection valve, PSEG inadvertently injected feedwater into the reactor vessel through the HPCI and core spray systems. Specifically, PSEG did not ensure that the post-modification test procedure established a system configuration appropriate for the plants operating condition. This resulted in an unanticipated reactor pressure and power transient. PSEGs corrective actions included revising the test procedure and re-performing the test.
The finding is more than minor because it is associated with the procedure quality attribute of the Initiating Events cornerstone, and it affected the cornerstone objective of limiting the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, an inadequate procedure resulted in an injection of feedwater through the HPCI core spray injection valve, which caused a pressure and power transient. The finding screened as Green (very low safety significance) because the finding did not contribute to both the likelihood of a reactor trip and the likelihood that mitigation equipment or functions would not be available. The finding has a cross-cutting aspect in the area of human performance because PSEG did not define and effectively communicate expectations regarding procedural compliance, and PSEG personnel did not follow procedures. Specifically, PSEG did not adequately implement the new procedure review process defined by PSEG procedure AD-AA-102-1001, Station Qualified Reviewers Guide, and, as a result, did not identify the adverse impact of the sequence of valve operations specified by the test procedure.
(H.4(b)) (Section 1R19)
Licensee Identified Violations
None.
REPORT DETAILS
Summary of Plant Status
The Hope Creek Generating Station (HCGS) operated continuously for the duration of the inspection period. From July 1 through August 22, the plant operated at approximately 97%
power consistent with PSEGs planned implementation of an extended power uprate (EPU). On August 22, operators increased reactor power to approximately 99% in accordance with the EPU test plan, and on August 26, operators increased reactor power to full rated thermal power (3840 megawatts thermal). On September 20, operators reduced power to 86% per direction from the transmission system operator in order to alleviate a high voltage condition on the transmission grid. Operators restored the plant to full power later that day. On September 26, operators performed a planned power reduction to approximately 76% for testing and maintenance. The plant was restored to full power on September
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 completed one adverse weather protection sample for PSEGs response to a site-specific weather-related condition of severe weather. Specifically, the inspectors verified that adverse weather conditions, thunderstorms and high winds that occurred on August 10 and 11, 2008, did not adversely impact mitigating systems or increase the likelihood of an initiating event. Inspectors discussed readiness with operations and work control personnel readiness and availability for adverse weather response.
b. Findings
No findings of significance were identified.
.2 Readiness to Cope with External Flooding
a. Inspection Scope
The inspectors completed one adverse weather protection sample for PSEGs response to a site-specific weather-related condition of severe weather that posed a risk of flooding on July 23, 2008. The inspectors walked down the station service water system and reactor building flood barriers to assure readiness. The inspectors also monitored various plant parameters that could be affected by the potential flooding condition using a computerized plant monitoring system. The inspectors verified that the adverse weather conditions did not adversely impact mitigating systems or increase the likelihood of an initiating event. Documents reviewed are listed in the Attachment.
b. Findings
No findings of significance were identified.
1R04 Equipment Alignment
.1 Partial Walkdown
a. Inspection Scope
The inspectors completed partial system walkdown inspection samples for the three systems listed below to verify the operability of redundant or diverse trains and components when safety equipment was unavailable. The inspectors completed walkdowns to determine whether there were discrepancies in the systems alignment that could impact the function of the system, and therefore, potentially increase risk. The inspectors reviewed applicable operating procedures, walked down control system components, and verified that selected breakers, valves, and support equipment were in the correct position to support system operation. The inspectors also verified that PSEG had properly identified and resolved equipment alignment problems that could cause initiating events or impact the capability of mitigating systems or barriers and entered them into the corrective action program. Documents reviewed are listed in the
.
- High pressure coolant injection (HPCI), reactor core isolation cooling (RCIC), and control rod drive systems during digital feedwater control system issues on July 17, 2008
- C service water (SW) pump during D SW pump outage on August 8, 2008
- B standby liquid control (SLC) during A SLC in-service test on August 26, 2008
b. Findings
No findings of significance were identified.
1R05 Fire Protection
.1 Fire Protection - Tours
a. Inspection Scope
The inspectors completed six quarterly fire protection inspection samples. The inspectors conducted tours of the six areas listed below to assess the material condition and operational status of fire protection features. The inspectors verified that combustibles and ignition sources were controlled in accordance with PSEGs administrative procedures; fire detection and suppression equipment was available for use; that passive fire barriers were maintained in good material condition; and that compensatory measures for out-of-service, degraded, or inoperable fire protection equipment were implemented in accordance with PSEGs fire plan. The six areas toured are listed below with their associated pre-fire plan designator. Other documents reviewed are listed in the Attachment.
- FRH-II-351, Remote shutdown panel room
- FRH-II-552, Control room & control console pit
- FRH-III-151, A recirculation motor generator (MG) set room
- FRH-III-151, B recirculation MG set room
- FRH-II-412, D residual heat removal (RHR) Pump Room
- FRH-II-413, C RHR Pump Room
b. Findings
No findings of significance were identified.
1R06 Flood Protection Measures
a. Inspection Scope
The inspectors completed one flood protection measure inspection sample. The inspectors reviewed selected risk-important plant design features and PSEG procedures intended to protect the plant and its safety-related equipment from internal flooding events. The inspectors focused on mitigation strategies and equipment in the B safety auxiliaries cooling system room. The inspectors reviewed flood analysis and design documents, including the Individual Plant Examination, updated final safety analysis report (UFSAR), engineering calculations, and abnormal operating procedures. The inspectors observed the condition of wall penetrations, watertight doors, flood alarm switches, and drains to assess their readiness to contain flow from an internal flooding event in accordance with the design basis.
Additionally, the inspectors reviewed flood protection related aspects of a declared Unusual Event for flooding in the service water intake structure. This event and NRC inspection activities are discussed in Section 4OA3 of this report.
b. Findings
No findings of significance were identified.
1R07 Heat Sink Performance
a. Inspection Scope
Based on a plant specific risk assessment and previous inspections, the inspectors selected three samples to review heat sink performance: A emergency diesel generator (EDG) lube oil heat exchanger (HX), A EDG jacket water HX, and performance of the ultimate heat sink (UHS) and its subcomponents. The safety auxiliaries cooling system (SACS) provides cooling to the EDG HXs and transfers its heat load to the SW system via the SACS HXs. The SW system supplies cooling water from the Delaware River (the UHS).
The inspectors reviewed the EDG HX and SW system material condition, testing, and operation to ensure that PSEG maintained these risk-significant components consistent with design assumptions in heat transfer calculations and the UFSAR. The inspectors reviewed PSEG evaluations and operational controls associated with the potential for water hammer, HX degradation due to excessive flow induced vibration, and system leakage. The inspectors also reviewed PSEGs inspection program for buried or inaccessible piping to verify that structural integrity and any leakage or degradation had been appropriately identified and dispositioned.
The inspectors reviewed the eddy current test methodology and results to verify that the number of plugged EDG HX tubes was bounded by assumptions in the engineering analyses. The inspectors reviewed the design fouling factor assumptions for the EDG HXs and the engineering analyses of minimum calculated SACS flowrate to the EDG HXs. This review was performed to verify that the minimum calculated SACS flowrate, in conjunction with the heat transfer capability of the EDG HXs , supported the minimum heat transfer rates assumed during accident and transient conditions. The inspectors reviewed EDG HX modeling analyses against the HX specification sheets to ensure the analysis was valid. This included calculations related to minimum allowable SACS flowrate to the HXs. The inspectors also reviewed SW silt survey results and engineerings associated trending data and action plans.
The inspectors compared surveillance test and inspection data to the established acceptance criteria to verify that the results were acceptable and that operation was consistent with design. The inspectors walked down the EDG HXs, control room instrumentation panels, SACS HXs, the chlorination system, and the SW intake to assess the material condition and configuration control of these structures, systems and components (SSCs).
The inspectors also reviewed a sample of corrective action notifications related to the selected HXs, SACS, and the SW system to ensure that PSEG appropriately identified, characterized, and corrected problems related to these essential systems and components. Documents reviewed are listed in the Attachment.
b. Findings
No findings of significance were identified.
1R11 Licensed Operator Requalification Program
.1 Requalification Activities Review by Resident Staff
a. Inspection Scope
The inspectors completed one requalification activities review inspection sample. The inspectors observed a licensed operator annual requalification simulator scenario on August 12, 2008, to assess operator performance and training effectiveness. The scenario involved a reactor recirculation pump trip, reactor water cleanup system leak, loss of main condenser vacuum, an anticipated transient without scram, and event classification. The inspectors verified that control room staff correctly identified and declared emergency action levels in a timely manner. The inspectors assessed simulator fidelity and observed the simulator instructors critique of operator performance. The inspectors also observed control room activities with emphasis on simulator identified areas for improvement. Finally, the inspectors reviewed applicable documents associated with licensed operator requalification as listed in the Attachment.
b. Findings
No findings of significance were identified.
1R12 Maintenance Effectiveness
a. Inspection Scope
The inspectors completed two maintenance effectiveness inspection samples. The inspectors evaluated items such as: appropriate work practices; identifying and addressing common cause failures; scoping in accordance with 10 CFR 50.65(b) of the maintenance rule (MR); characterizing reliability issues for performance; trending key parameters for condition monitoring; charging unavailability for performance; classification and reclassification in accordance with 10 CFR 50.65(a)(1) or (a)(2); and appropriateness of performance criteria for structures, systems, and components (SSCs)/functions classified as (a)(2) and/or appropriateness and adequacy of goals and corrective actions for SSCs/functions classified as (a)(1). Documents reviewed are listed in the Attachment.
- A control room chilled water pump trips
- CD 482 inverter failures
b. Findings
No findings of significance were identified.
1R13 Maintenance Risk Assessments and Emergent Work Control
a. Inspection Scope
The inspectors completed five maintenance risk assessment and emergent work control inspection samples. The inspectors reviewed on-line risk management evaluations through direct observation and document reviews for the following five configurations:
- L safety relief valve (SRV) acoustic monitor failure and B SW pump out of service on July 17, 2008;
- HPCI jockey pump and L SRV acoustic monitor out of service during adverse weather on August 10, 2008;
- B control room ventilation train and CD 481 inverter out of service during CD 481 inverter fan replacement on August 21, 2008;
- L SRV acoustic monitor and C reactor building ventilation supply out of service during power ascension August 22, 2008; and
- D EDG supply fan and L SRV acoustic monitor out of service during an unusual event declaration due to B and D SW bay internal flooding on August 28, 2008.
The inspectors reviewed the applicable risk evaluations, work schedules and control room logs for these configurations to verify that concurrent planned and emergent maintenance and test activities did not adversely affect the plant risk already incurred with these configurations. PSEGs risk management actions were reviewed during shift turnover meetings, control room tours, and plant walkdowns. The inspectors also used PSEGs on-line risk monitor (Equipment Out-Of-Service workstation) to gain insights into the risk associated with these plant configurations. Finally, the inspectors reviewed notifications documenting problems associated with risk assessments and emergent work evaluations to verify that problems in this area were identified and corrected.
Documents reviewed are listed in the Attachment.
b. Findings
No findings of significance were identified.
1R15 Operability Evaluations
a. Inspection Scope
The inspectors completed six operability evaluation inspection samples. The inspectors reviewed the operability determinations for degraded or non-conforming conditions associated with:
- CD482 inverter failure on on July 6, 2008;
- Gas intrusion that affected the A control room chilled water pump on July 9, 2008;
- SW bay high silt levels on August 22, 2008;
- D EDG SACS outlet cooling water valve failure on August 22, 2008;
- HPCI/RCIC room temperatures above the temperature assumed in station blackout (SBO) calculation on September 9, 2008; and
- D SRV tailpipe temperature fluctuations on September 13, 2008.
The inspectors reviewed the technical adequacy of the operability determinations to ensure the conclusions were justified. The inspectors walked down accessible equipment to corroborate the adequacy of PSEGs operability determinations.
Additionally, the inspectors reviewed other PSEG identified safety-related equipment deficiencies during this report period and assessed the adequacy of their operability screenings. Documents reviewed are listed in the Attachment.
b. Findings
No findings of significance were identified.
1R18 Permanent Plant Modifications
a. Inspection Scope
The inspectors completed a review of one permanent plant modification design change package for service water strainer differential pressure indication. This modification was installed to allow monitoring of strainer differential pressure over a wider range, where the existing transmitter may have gone offscale during high grassing events. The inspectors verified that the design bases, licensing bases, and performance capability of the SW system was not degraded by the modification. The inspectors also verified that the new configuration was accurately reflected in the design documentation, and that post-modification testing was adequate to ensure that the affected structures, systems, and components would function properly after modification installation. The inspectors interviewed plant staff, and reviewed issues entered into the corrective action program to to verify that PSEG was effective at identifying and resolving problems associated with plant modifications. The 10 CFR 50.59 evaluation associated with the SW differential pressure modification was also reviewed. Other documents reviewed for this inspection are listed in the Attachment.
b. Findings
No findings of significance were identified.
1R19 Post-Maintenance Testing
a. Inspection Scope
The inspectors completed six post-maintenance testing inspection samples. 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 test procedures to verify that the procedure adequately tested safety functions that may have been affected by the maintenance activity and that the acceptance criteria in the procedure were consistent with the UFSAR and other design documentation. The inspectors witnessed the test or reviewed the test data to verify that test results adequately demonstrated restoration of the affected safety functions. Documents reviewed are listed in the Attachment.
- D RHR pump planned maintenance on July 23, 2008
- HPCI isolation relay replacement after failed high area room temperature channel calibration on August 1, 2008
- SW strainer differential pressure planned maintenance on August 13, 2008
- Remote shutdown panel instrumentation planned maintenance on August 14, 2008
b. Findings
Introduction:
A Green self-revealing, non-cited violation of Technical Specification 6.8.1, Procedures and Programs, was identified because, during performance of post-modification testing for the HPCI feedwater injection valve, PSEG inadvertently injected feedwater into the reactor vessel through the HPCI and core spray systems.
Specifically, PSEG did not ensure that the post-modification test procedure established a system configuration appropriate for the plants operating condition. This resulted in an unanticipated reactor pressure and power transient.
Description:
At HCGS, the HPCI system was designed to respond to a small or large break loss of coolant accident by injecting water into the reactor core using two flow paths: a feedwater injection line and a core spray injection line. On June 24, 2008, while performing a post modification test on the HPCI feedwater injection line isolation valve, BJ-HV-8278, operators inadvertently injected feedwater into the reactor vessel through the HPCI core spray injection line isolation valve, BJ-HV-F006. The procedure used to complete the post modification test directed operators to open both the core spray and feedwater HPCI system injection valves. Due to the plant operating condition on June 24, when both injection valves were opened feedwater flow was diverted from the feedwater injection line through the HPCI core spray injection line into the reactor vessel. This resulted in an unanticipated reactor pressure and power transient.
PSEG performed a root cause evaluation of the event and determined that the root cause of the inadvertent feedwater injection was an inadequate procedure, HC.OP-ST.BJ-0003, HPCI System Valve Actuation Functional Test. This procedure was written on June 20, 2008, to revise the test methodology for HPCI system valves.
PSEGs procedure, AD-AA-101, Processing of Procedures and T&RMs, established guidance for writing and revising procedures. PSEG stated in its root cause that the test procedure was not reviewed using the guidance in AD-AA-102-1001, Station Qualified Reviewers Guide, as directed by AD-AA-101. For example, the procedure stated that when reviewing the evolution for the potential adverse impact on plant operation, reviewers should consider the sequence of valve operations to verify that it did not result in cross-connecting with undesired systems or portions of systems. However, the configuration was not fully reviewed using this guidance; therefore, PSEG did not identify the unintended consequence of the procedure steps that directed both the HPCI feedwater injection valve and the HPCI core spray injection valve to be opened at the same time. PSEGs corrective actions for the event included revising the procedure and re-performing the test. Additionally, PSEG initiated actions to improve the procedure technical review process.
The inspectors reviewed the event and PSEGs cause analysis and determined that PSEG did not maintain an adequate procedure for performing post-modification testing for the HPCI feedwater injection valve. Specifically, PSEG created procedure HC.OP-ST.BJ-0003, HPCI System Valve Actuation Functional Test, but did not identify the unintended injection path established by the procedure. As a result, implementation of the procedure caused an inadvertent injection of feedwater through the HPCI core spray injection valve that caused an inadvertent reactor power and pressure transient. The inspectors determined that this was a performance deficiency because the procedure change process defined by procedure AD-AA-1001, Processing of Procedures and T&RMs, directed that the procedure be reviewed to identify undesired system interactions.
Analysis:
The finding is more than minor because it is associated with the procedure quality attribute of the Initiating Events cornerstone, and it affected the cornerstone objective of limiting the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, the inadequate procedure resulted in feedwater injection through the HPCI core spray injection valve, which caused a pressure and power transient. The inspectors performed a Phase I screening of the finding in accordance with Inspection Manual Chapter 0609.04, Phase I - Initial Screening and Characterizing of Findings. The finding screened as Green (very low safety significance) because the finding did not contribute to both the likelihood of a reactor trip and the likelihood that mitigation equipment or functions would not be available.
The finding had a cross-cutting aspect in the area of human performance because PSEG did not define and effectively communicate expectations regarding procedural compliance, and PSEG personnel did not follow procedures. Specifically, PSEG did not adequately implement the procedure review process defined by PSEG procedure AD-AA-102-1001, Station Qualified Reviewers Guide, and, as a result, did not identify the adverse impact of the sequence of valve operations specified by the test procedure.
(H.4(b))
Enforcement:
Hope Creek Technical Specification 6.8.1, Procedures and Programs, requires, in part, that written procedures shall be established, implemented, and maintained covering test activities for safety-related equipment. Contrary to the above, on June 20, 2008, PSEG did not adequately maintain written procedures covering test activities associated with the HPCI feedwater injection valve. Specifically, on June 20, 2008, PSEG created procedure HC.OP-ST.BJ-0003, HPCI System Valve Actuation Functional Test, but did not identify that the procedure directed both the HPCI feedwater injection valve and the HPCI core spray injection valve to be opened at the same time. On June 24, 2008, implementation of the procedure caused an inadvertent injection of feedwater through the HPCI core spray injection valve that caused an inadvertent power and pressure transient. Because this finding was of very low safety significance and was entered into the corrective action program in notification 20374972, this violation is being treated as an NCV, consistent with section VI.A.1 of the NRC Enforcement Policy. (NCV 05000354/2008004-01, Inadvertent Feedwater Injection Through the High Pressure Coolant Injection System Due to an Inadequate Test Procedure)
1R22 Surveillance Testing
a. Inspection Scope
The inspectors completed six surveillance testing (ST) inspection samples. The inspectors witnessed performance of and/or reviewed test data for the risk-significant STs to assess whether the SSCs tested satisfied TS, UFSAR, and procedure requirements. The inspectors verified that test acceptance criteria were clear, demonstrated operational readiness and were consistent with design documentation; that test instrumentation had current calibrations and the range and accuracy for the application; and that tests were performed, as written, with applicable prerequisites satisfied. Upon ST completion, the inspectors verified that the equipment was returned to the status that was required for the system to perform its safety function. Documents reviewed for the inspection are listed in the Attachment.
- A residual heat removal pump 2-year comprehensive test on July 1, 2008
- Standby liquid control system sodium pentaborate analysis on July 17, 2008
- D EDG monthly test on July 21, 2008
- Reactor building to torus vacuum breaker test on July 23, 2008
- Drywell sump leak detection on July 22, 2008
- HPCI in-service test on September 5, 2008
b. Findings
No findings of significance were identified.
Cornerstone: Emergency Preparedness
1EP6 Drill Evaluation
a. Inspection Scope
The inspectors completed one drill evaluation inspection sample. The inspectors observed control room operator emergency plan response actions during an evaluated licensed operator requalification scenario on August 12, 2008. The inspectors verified that emergency classification declarations and notifications were completed in accordance with 10 CFR 50.72, 10 CFR 50, Appendix E, and the Hope Creek emergency plan implementing procedures. Documents reviewed are listed in the
.
b. Findings
No findings of significance were identified.
1EP7 Emergency Preparedness Component of the Force-On-Force (FOF) Exercise Evaluation
a. Inspection Scope
The inspectors observed PSEGs performance during the site emergency preparedness component of the FOF exercise. The inspectors observed communications, event classification, and event notification activities by the simulated shift manager. The inspectors also observed portions of the post-exercise critique to determine whether their observations were also identified by PSEGs evaluators. The inspectors verified that minor issues identified during this inspection were entered into PSEGs corrective action program. Documents reviewed are listed in the Attachment.
b. Findings
No findings of significance were identified.
RADIATION SAFETY
Cornerstone: Occupational Radiation Safety
2OS1 Access Control to Radiologically Significant Areas (71121.01 - 11 samples)
a. Inspection Scope
The inspectors identified exposure-significant work areas within radiation areas, high radiation areas (<1 R/hr), or airborne radioactivity areas in the plant and reviewed associated PSEG controls and surveys of these areas to verify that controls were acceptable.
Using a survey instrument, the inspectors walked down these areas or their perimeters to verify: that prescribed radiation work permits, procedure, and engineering controls were in place; that PSEG surveys and postings were complete and accurate; and that air samplers were properly located.
The inspectors reviewed radiation work permits used to access these and other high radiation areas to identify the specified work control instructions or control barriers. The inspectors compared the specified barriers to the plant-specific technical specification high radiation area barrier requirements. The inspectors reviewed electronic personal dosimeter alarm set points to verify conformity with survey indications and plant policy and interviewed workers to verify their knowledge regarding actions required for electronic personal dosimeter malfunctions and alarms.
The inspectors reviewed radiation work permits for airborne radioactivity areas with the potential to cause individual worker internal exposures of more than 50 mrem committed effective dose equivalent. For these selected airborne radioactive material areas, the inspectors assessed barrier integrity and engineering controls performance.
The inspectors selected two to three scheduled jobs that were performed in radiation areas, airborne radioactivity areas, or high radiation areas. The inspectors then observed work that was: estimated to result in the highest collective doses; involved diving activities in or around spent fuel or highly activated material; or that involved potentially deteriorating radiological conditions. For the selected jobs, the inspectors reviewed all radiological job requirements and assessed job performance with respect to these requirements including whether radiological conditions at the job site were adequately communicated to workers through briefings and postings.
During job performance observations the inspectors assessed the adequacy of radiological controls, including surveys, radiation protection technician job coverage, and contamination controls.
For high radiation work areas with significant dose rate gradients, the inspectors assessed the adequacy of the dosimetry used to monitor personnel exposure.
During job performance observations, the inspectors observed radiation worker performance to verify adherence to radiation protection work requirements and that job performance took into consideration the level of radiological hazards present at the job site. The inspectors interviewed workers to verify that they were aware of significant radiological conditions at the job site and the radiation work permit controls and limits that were in place.
During job performance observations, the inspectors also observed radiation protection technician performance to verify adherence to radiation protection work requirements and that technician performance was consistent with their training and qualifications.
The inspectors also interviewed the technicians to verify that they were aware of significant radiological conditions at the job site and the radiation work permit controls and limits that were in place.
The inspectors discussed, with the radiation protection manager, procedure changes completed since the last inspection that affected high dose rate high radiation area and very high radiation area controls to verify that the changes did not negatively impact the effectiveness and level of worker radiation protection at HCGS.
The inspectors discussed, with health physics supervisors, the controls in place for plant areas that had the potential to become very high radiation areas during certain plant conditions to verify that communication with the health physics group was required prior to entering those plant conditions to allow proper posting and control of the radiation hazards.
The inspectors evaluated PSEG performance in the above areas against the requirements contained in 10 CFR 20.1601, TS 6.12, High Radiation Area, and UFSAR Section 12, Radiation Protection.
b. Findings
No findings of significance were identified.
2OS2 ALARA Planning and Controls (71121.02 - 2 samples)
a. Inspection Scope
The inspectors assessed radiation worker and radiation protection technician performance by observing work activities performed in radiation areas, airborne radioactivity areas, or high radiation areas that presented the greatest radiological risk to the workers and technicians involved. The inspectors assessed worker and technician performance with respect to the ALARA principles and compliance with procedure requirements. The inspectors also assessed the effectiveness of training related to the radiological hazards present and the work involved based on worker performance.
The inspectors determined that there were four declared pregnant workers during the assessment period. The inspectors reviewed the exposure results and monitoring controls employed by the licensee for these workers to verify compliance with the requirements of 10 CFR 20.
The inspectors evaluated PSEG performance in these areas against the requirements contained in 10 CFR 20.1101 and UFSAR Section 12.1.
b. Findings
No findings of significance were identified.
2OS3 Radiation Monitoring Instrumentation and Protective Equipment (71121.03 - 1 sample)
a. Inspection Scope
The inspectors identified the types of portable radiation detection instrumentation used for job coverage of high radiation area work, temporary area radiation monitors currently used in the plant, and continuous air monitors associated with jobs with the potential for workers to receive 50 mrem committed effective dose equivalent.
The inspectors evaluated PSEG performance in this area against the requirements contained in 10 CFR 20.1501, 10 CFR 20.1703 and 10 CFR 20.1704.
b. Findings
No findings of significance were identified.
OTHER ACTIVITIES
4OA1 Performance Indicator Verification
a. Inspection Scope
Cornerstone: Mitigating Systems
The inspectors reviewed PSEGs submittal for the safety system functional failure (SSFF) performance indicator. The inspectors verified the accuracy and completeness of reported SSFFs during the period of July 1, 2007, through June 30, 2008, using guidance contained in NEI 99-02, Regulatory Assessment Indicator Guideline, Revision 5. The inspectors reviewed all PSEG licensee event reports issued during the referenced time frame to independently verify that SSFFs were correctly reflected in the performance indicator data.
b. Findings
No findings of significance were identified.
4OA2 Identification and Resolution of Problems
.1 Review of Items Entered into the Corrective Action Program:
As required by Inspection Procedure 71152, Identification and Resolution of Problems, and in order to help identify repetitive equipment failures or specific human performance issues for follow-up, the inspectors performed a daily screening of all items entered into PSEG's corrective action program. This was accomplished by reviewing the description of each new notification and attending daily management review committee meetings.
.2 Annual Sample: Containment Vacuum Breaker Issues
a. Inspection Scope
The inspectors reviewed PSEGs actions to address multiple reactor building/torus and torus/drywell vacuum breaker testing issues over the past few years. PSEG had observed instances in which a vacuum breaker would not open as expected during surveillance testing. More recently, issues were identified during surveillance testing where the limit switch would not change state when opening or closing a vacuum breaker. The issues were selected for review based on their repetitive nature and potential risk significance. The inspectors reviewed notifications, orders, procedures, and corrective actions associated with the vacuum breaker issues. Additionally, the inspectors interviewed the system engineer and control room operators to gain additional insights on the issues.
b. Findings and Observations
No findings of significance were identified.
The inspectors determined that PSEG appropriately identified the issues and entered them into the corrective action program. The inspectors noted two separate repeating issues, one in 2005 and 2006 and the other in 2006 and 2007.
In 2005 and 2006, PSEG had difficulties with the vacuum breakers failing to open during surveillance testing. Corrective actions included a change to the test procedure to relieve pressure in the line prior to testing so the test actuator could open. The inspectors concluded that the corrective actions were appropriate and effective.
In 2006 and 2007, there were repeat issues with vacuum breaker limit switches failing.
These limit switches were used during surveillance testing to ensure the vacuum breakers were fully closed. The inspectors concluded that PSEG took appropriate corrective actions to replace vacuum breaker limit switches and used, as needed, an alternative method to verify that the vacuum breakers were closed.
.3 Annual Sample: Operator Workarounds
a. Inspection Scope
The inspectors performed a cumulative review of PSEGs identified operator workaround conditions. The inspectors reviewed PSEGs list of operator burdens and concerns, temporary modifications, and operability determinations to assess the potential for these issues to impact the operators' ability to properly respond to plant transients or postulated accident conditions. In addition, the inspectors reviewed PSEGs list of deficient control room computer points and locked-in overhead annunciators to determine whether operators could adequately identify degraded plant equipment. The inspectors also reviewed operator logs and control room instrument panels to evaluate potential impacts on operator ability to implement abnormal and emergency operating procedures. Finally, the inspectors toured the plant and control room to identify potential workaround conditions not previously identified by PSEG. Documents reviewed for this inspection activity are listed in the Attachment.
b. Findings and Observations
No findings of significance were identified.
The inspectors determined that PSEG appropriately identified the issues and entered them into the corrective action program. Operations personnel reviewed the impact of operator burdens, concerns, and workarounds on a periodic basis.
4OA3 Event Followup
.1 Service Water Intake Structure Flooding Unusual Event
a. Inspection Scope
On August 28, 2008, at 4:47 am, PSEG declared an unusual event for flooding in the service water intake structure, based upon receipt of the B and D service water intake structure flooded alarm and visual verification of water on the room floor. PSEG exited the unusual event at 7:36 am on August 28, 2008, pumped out the water using a portable sump pump, and repaired the switches. The inspectors responded to the service water intake structure to assess plant conditions and to observe operator performance during the event.
b. Findings
PSEG determined that the service water intake structure flooded because of a degraded sump float switch and a failed sump alarm switch, combined with increased packing leakage on the D service water pump. PSEG initiated three causal evaluations to determine the apparent causes of various conditions related to this Unusual Event. The inspectors will review these causal evaluations upon completion. The inspectors consider this issue unresolved pending PSEGs completion of the causal evaluations and review by the inspectors. (URI 05000354/2008004-02, Service Water Intake Structure Flooding Unusual Event)
4OA5 Other Activities
.1 Operation of an Independent Spent Fuel Storage Installation at Operating Plants
(60855.1 - 1 sample)
a. Inspection Scope
The inspectors observed selected activities associated with the loading of a dry cask fuel storage canister to ensure that TS were met, equipment operated properly, and personnel were properly trained. The inspectors reviewed radiological surveys of the cask work area with the lead radiation protection technician. The inspectors interviewed a training coordinator regarding the crew training and qualifications, and examined the personnel qualification logs. The inspectors interviewed an engineer with the ALARA group and reviewed the target and actual cumulative doses for the first three casks of the current campaign. The inspectors discussed the procedural, personnel, and equipment changes with the dry cask manager and reviewed the readiness review document that was created prior to the start of the second loading campaign. The inspectors observed equipment improvements made to the blow down, vacuum drying, and helium back filling processes.
b. Findings
No findings of significance were identified.
.2 Power Uprate
a. Inspection Scope
Power Ascension Activities During the period August 22 through 26, 2008, PSEG conducted power ascension activities in accordance with an extended power uprate (EPU) test plan. The inspectors performed portions of NRC procedure 71004, Power Uprate, during this period to verify that equipment performance, procedures, and processes were adequate to support operations at the increased power level. On August 26, the station reached 100% of the new maximum power level (3840 megawatts thermal).
Actions for New or More Likely Initiating Events The inspectors reviewed PSEGs safety evaluation report regarding the potential for new or more likely initiating events. The inspectors also interviewed operations and training department staff, and performed simulator reviews to determine PSEGs actions for addressing new or likely initiating events for the EPU. Emergency operating procedures and computer alarm setpoint changes were reviewed. Additionally, the inspectors reviewed risk assessments for power ascension and the potential for new or more likely initiating events.
b. Findings
No findings of significance were identified.
.3 Quarterly Resident Inspector Observations of Security Personnel and Activities
a. Inspection Scope
During the inspection period the inspectors conducted observations of security force personnel and activities to ensure that the activities were consistent with licensee security procedures and regulatory requirements relating to nuclear plant security.
These observations took place during both normal and off-normal plant working hours.
These quarterly resident inspector observations of security force personnel and activities did not constitute any additional inspection samples. Rather, they were considered an integral part of the inspectors' normal plant status reviews and inspection activities.
b. Findings
No findings of significance were identified.
4OA6 Meetings, Including Exit
The resident inspectors presented the inspection results to Mr. George Barnes and other members of PSEG staff on October 15, 2008. PSEG stated that none of the material reviewed by the inspectors during this period was proprietary.
ATTACHMENT:
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee Personnel
- G. Barnes, Site Vice President
- B. Booth, Operations Director
- R. Canziani, Maintenance Director
- E. Casulli, Shift Operations Superintendent
- K. Chambliss, Assistant Plant Manager
- K. Knaide, Engineering Director
- M. Gaffney, Regulatory Assurance Manager
- J. Perry, Plant Manager
- H. Trimble, Radiation Protection Manager
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened/Closed
- 05000354/2008004-01 NCV Inadvertent Feedwater Injection Through the High Pressure Coolant Injection System Due to an Inadequate Test Procedure (Section 1R19)
Opened
- 05000354/2008004-02 URI Service Water Intake Structure Flooding Unusual Event (Section 4OA3)