IR 05000272/2010005
| ML110390451 | |
| Person / Time | |
|---|---|
| Site: | Salem  |
| Issue date: | 02/08/2011 |
| From: | Arthur Burritt Reactor Projects Branch 3 |
| To: | Joyce T Public Service Enterprise Group |
| BURRITT AL | |
| References | |
| IR-10-005 | |
| Download: ML110390451 (34) | |
Text
UNITED STATES NUCLEAR REGULATORY COMMISSION
REGION I
475 ALLENDALE ROAD KING OF PRUSSIA. PA 19406.1415 February 8, 20lI Mr. Thomas President and Chief Nuclear Officer PSEG Nuclear LLC - N09 P.O. Box 236 Hancock's Bridge, NJ 08038 SUBJECT: SALEM NUCLEAR GENERATING STATION, UNIT NoS. 1 AND 2 -
NRC INTEGRATED INSPECTION REPORT 05000272t2010005 and 0500031 1t2010005
Dear Mr. Joyce:
On December 31 ,2010, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at the Salem Nuclear Generating Station,'Unit Nos. 1 and 2. The enclosed integrated inspection report documents thainspection results discussed on January 6, 2011, with Mr. Fricker and other members of your staff.
The inspection examined activities conducted under your license as they relate to safety and compliance with the Commission's rules and regulations and with the conditions of youi 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). This finding was determined to involve a violition of NnC requirements. However, because of the Yery- lgry safety significance and because it is entered inio your corrective action program (CAp),
is treating this finding as a non-cited violation (trtiv) consistent with Sectio n 2.3.2 ot l'," lll9 the NRC Enforcement Policy. lf you contest the NCV in this ieport, you should provide a response within 30 days of the date of this inspection report, witn tne basis for your denial, to the_Nuclear Regulatory Commission, ATTN: Document bonirot Desk, Washington, DC 20SSb-9.09t; w_ith copies to the Regional Administrator, Region l; the Director, office 6f Enforcement, United States Nuclear Regulatory Commission, WaJhington, DC 2OS5b-0001; and the NRC Resident Inspector at the Salem Nuclear Generating StJtion. ln addition, if you disagree with th.9 9ro5-gutting aspect assigned to any finding in this report, you should provide a risponse within 30 days of the date of this inspection rep-ort, with the baiis of your dir"gr"ement, to the RegionalAdministrator, Region 1, and the NRC Resident Inspector it Satem iluclear Generating Station. In accordance with 10 Code of Federal Regulations (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.qov/readino-rm/adams.html (the Public Electronic Reading Room).
Sincerely n
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Arthur L. Burritt, Chief Projects Branch 3 Division of Reactor Projects Docket Nos: 50-272:50-31 1 License Nos: DPR-70; DPR-75
Enclosure:
lnspection Report 0500027212010005 and 0500031 1/201 0005 w/Attachment: Supplemental I nformation
REGION I 50-272,50-31 1 License Nos: DPR-70, DPR-75 Report No: 050002721201 0005 and 0500031 1 /201 0005 Licensee: PSEG Nuclear LLC (PSEG)
Facility: Salem Nuclear Generating Station, Unit Nos. 1 and 2 P.O. Box 236 Hancocks Bridge, NJ 08038 October 1,2010 through December 31,2010 D. Schroeder, Senior Resident Inspector P. McKenna, Resident Inspector E. Torres, Acting Resident Inspector C. Douglas, Project Engineer J. Furia, Senior Health Physicist J. Schoppy, Senior Reactor Inspector L. Scholl, Senior Reactor lnspector M. Patel, Reactor lnspector T. O'Hara, Reactor Inspector Approved By: Arthur L. Burritt, Chief Projects Branch 3 Division of Reactor Projects Enclosure
SUMMARY OF FINDINGS
lR 0500027212010005, 05000311/2010005i 1010112010 - 1213112010; Salem Nuclear
Generating Station Unit Nos. 1 and 2; Maintenance Effectiveness.
The report covered a three-month period of inspection by resident inspectors, and announced inspections by regional specialist inspectors. One Green non-cited violation (NCV) was identified. The significance of most findings is indicated by their color (Green, White, Yellow, or Red) and determined using Inspection Manual Chapter (lMC) 0609, "Significance Determination Process" (SDP). The cross-cutting aspect of a finding is determined using the guidance in IMC 0310, "Components Within the Cross-Cutting Areas". Findings for which the SDP does not apply may be Green or be assigned a severity level after NRC management review. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, "Reactor Oversight Process," Revision 4, dated December 2006.
Cornerstone: Mitigating Systems
.
- Green.
A self-revealing NCV of Appendix B, Criterion V, "lnstructions, Procedures, and Drawings", was identified because of two unexpected trips of the turbine trip valve (1MS52) for the 13 turbine driven auxiliary feedwater (TDAFW) pump. Specifically, adjustments made to the overspeed linkage for the 13 TDAFW pump using a threaded rod, which was installed on the head lever, were not prescribed by documented procedures or drawings. These adjustments led to the increased sensitivity of the trip mechanism that resulted in the two unexpected trips. The issue was entered into the CAP as notification 20469586. PSEGs immediate corrective action was to remove the threaded rod from the 13 TDAFW head lever. An extent of condition inspection on the 23 TDAFW pump resulted in the removal of a threaded rod from the 23 TDAFW pump head lever.
The trips of the 1MS52 valve and repairs to the overspeed trip mechanism resulted in 41 hours4.74537e-4 days <br />0.0114 hours <br />6.779101e-5 weeks <br />1.56005e-5 months <br /> of unavailability of the 13 TDAFW pump. fn accordance with NRC IMC 0609,
Attachment 4, the inspectors performed a Phase 1 SDP screening and determined the finding was of very low safety significance (Green) because it was not a design or qualification deficiency, did not result in an actual loss of safety function, and was not potentially risk significant for external events. This finding had a cross-cutting aspect in the area of human performance, resources, because PSEG did not ensure that complete accurate and up{o-date procedures and work packages were available and adequate to assure nuclear safety. Specifically, the procedure used to set the overspeed trip did not address adjustment of the threaded rod. (H.2(c)) (Section 1R12)
REPORT DETAILS
Summarv of Plant Status Salem Nuclear Generating Station Unit No. I (Unit 1) began the period at 98 percent power. On October 9, operators reduced power to 30 percent to perform repairs on valve 128,522. Unit 1 was returned to full power on October 10. On October 15, Unit 1 tripped due to generator protection causing a turbine trip, which caused a reactor trip. Unit 1 was synchronized to the grid on October 18 and full power was reached later the same day. On October 20, operators reduced power to 55 percent because of a high voltage condition on the grid. Unit 1 returned to 100 percent power on October 23. Unit 1 remained at or near full power for the remainder of the inspection period.
Salem Nuclear Generating Station Unit No. 2 (Unit 2) began the period at full power. On October 17, Unit 2 tripped due to low voltage output from the main generator. Unit 2 was synchronized to the grid on October 20, and power ascension placed on hold at 50 percent power due to power grid limitations. Unit 2 was returned to 100 percent power on October 23.
Unit 2 remained at or near full power for the duration of the inspection period,
1. REACTORSAFETY
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, and Emergency Preparedness
1R01 Adverse Weather Protection
Readiness for Seasonal Extreme Weather Conditions.
a. Inspection Scope
The inspectors completed one seasonal extreme weather preparation inspection sample for the onset of cold weather. The inspectors reviewed cold weather preparations to verify PSEG adequately prepared equipment to operate reliably in extreme cold weather conditions. Specifically, the inspectors walked down the service water (SW) intake structure, fire pump house, and radioactive water, auxiliary feedwater (AFW) and primary water storage tanks to verify that design features used to maintain these systems functional during cold weather conditions were adequately maintained.
Documents reviewed are listed in the Attachment.
b.
Findinos No findings were identified.
1R04 Equipment Aliqnment
PartialWalkdown
a. Inspection Scope
The inspectors completed three partial system walkdown inspection samples. The inspectors walked down the systems listed below to verify the operability of redundant or diverse trains and components when safety equipment was inoperable. The inspectors focused their review on potential discrepancies that could impact the function of the system and increase plant risk. The inspectors reviewed applicable operating procedures, walked down control systems 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 properly utilized its CAP to identify and resolve equipment alignment problems that could cause initiating events or impact the capability of mitigating systems or barriers. Documents reviewed are listed in the
.
.
Unit 1 , 1A and 1C emergency diesel generators (EDGs) with 1B EDG out of service (OOS) on November 1 o Unit 1, 1B and 1C EDGs with 14 EDG OOS on November 30
.
Unit 1, 14 and 1B EDGs with 1C EDG OOS on December 16 b. Findinos No findings were identified.
1R05 Fire Protection (71 11 1.05Q - 5 samples)
Fire Protection - Tours
a. Inspection Scope
The inspectors completed five fire protection quarterly inspection samples. The inspectors walked down the systems 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 PSEG's 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 OOS, degraded, or inoperable fire protection equipment were implemented in accordance with PSEG's fire plan. Documents reviewed are listed in the Attachment.
r Unit 1 and Unit 2, 460 Vac switchgear room and corridor, 84'elevation
.
Unit 1 and Unit 2, control room area, 100'elevation o Unit 2, auxiliary equipment area, 45' and 55' elevation b. Findinqs No findings were identified.
1R07 Heat Sink Performance (71111.07A - 1 sample;71111.07T - 1 sample)
.1 Annual Heat Sink Performance
a.
Inspection Scooe The inspectors completed one heat sink performance inspection sample. The inspectors reviewed performance data and interviewed the NRC Generic Letter (GL) 89-13 program manager to verify that potential heat exchanger (HX) or heat sink deficiencies were identified and PSEG adequately resolved heat sink performance problems. Specifically, the inspectors reviewed a biofouling test conducted on the 12 charging and volume control pump lube oil and gear oil coolers. The inspectors evaluated trending data and verified that equipment would perform satisfactorily under design basis conditions. The method of performance monitoring was compared to the guidance provided in NRC GL 89-13, "Service Water System Problems Affecting Safety-Related Equipment", and Electric Power Research Institute NP 7552, "HX Performance Monitoring Guidelines".
Documents reviewed are listed in the Attachment.
b. Findinqs No findings were identified.
.2 Triennial Heat Sink PerformanE
a. Inspection Scope
Based on plant specific risk assessment, previous inspections, recent operational experience, and resident inspector input, the inspectors selected the following heat sink samples:
.
1A EDG jacket water HX; o 14 EDG lube oil HX; and
.
Performance of the ultimate heat sink (UHS) including SW piping integrity and intake structu re functiona ity I
The Delaware River functions as the UHS for both Salem units. The safety-related SW pumps take suction from the Delaware River and supply cooling to the EDG HXs through redundant supply headers for each unit. In addition, the SW system also supplies cooling to the safety injection (Sl) pump lube oil and room coolers, component cooling water (CCW) HXs and room coolers, centrifugal charging pump gear oil and lube oil coolers, containment fan cooler units (CFCUs), and safety-related chillers.
The inspectors reviewed PSEG's methods (inspection, cleaning, maintenance, and performance monitoring) used to ensure heat removal capabilities for the 1A EDG HXs and compared them to PSEG's commitments made in response to GL 89-13, "Service Water System Problems Affecting Safety-Related Equipment." The inspectors reviewed the inspection work orders and eddy current test results to verify that the as-found and as-left condition of the EDG HXs were bounded by assumptions in the engineering analyses and provided reasonable assurance of continued operability. The inspectors reviewed engineering analyses to verify that the minimum calculated SW 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 analyses used conservative assumptions and appropriate design inputs. The inspectors compared EDG surveillance data to the established acceptance criteria to verify that the results were acceptable and that operation was consistent with design.
The inspectors reviewed PSEG's procedures for SW and intake structure operation, abnormal SW operations, adverse weather conditions, cold weather preparations, and SW leak isolation. The inspectors verified that PSEG maintained these procedures consistent with their design and licensing basis and that plant operators could reasonably implement the procedures as written. The inspectors independently verified that SW instrumentation that operators rely on for decision making was available and functional. On several cold days during the week of December 6, 2010, the inspectors performed additional focused walkdowns of the SW and circulating water (CW) intake areas to assess SW and CW system functionality during adverse weather conditions, including an independent functional check of a sample of SW and CW watertight doors.
The inspectors reviewed PSEG's SW pipe inspection and monitoring program to assess the condition and structural integrity of the SW piping. The inspectors reviewed a sample of SW pipe nondestructive examination records, intake structure inspections, maintenance history, and associated engineering evaluations to ensure that PSEG appropriately identified and dispositioned any SW piping or intake structure degradation.
The inspectors performed several detailed walkdowns of accessible areas containing SW piping to look for indications of piping leakage and/or degradation. The inspectors walked down control room instrument panels, accessible portions of SW piping in the turbine and auxiliary buildings (including the EDG HXs), the Unit 2 SW pipe tunnel, and the intake area (including the trash racks, SW pumps and strainers, SW traveling water screens, and structural supports) to access 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 SW valves, pumps, structural supports, and piping integrity to ensure that PSEG appropriately identified, characterized, and corrected problems related to these essential SSCs. Documents reviewed are listed in the Attachment.
b.
Findinqs No findings were identified.
1R1 1 Licensed Operator Requalification Proqram (71111.1 1Q - 1 sample:71111.118 - 1 sample)
.1 Requalification Activities Review bv Resident Staff
a. Inspection Scope
The inspectors completed one quarterly licensed operator requalification program inspection sample. Specifically, the inspectors observed two scenarios administered to one crew on October 5,2010. The first scenario included a chill water leak, loss of SW to the main turbine, turbine trip failure, and a faulted steam generator. The second scenario included a power range nuclear instrument failure, a loss of coolant accident, a loss of offsite power, and a recoverable station blackout. The inspectors reviewed operator actions to implement the abnormal and emergency operating procedures, The inspectors examined the operators'ability to perform actions associated with high risk activities, the Emergency Plan, previous lessons learned items, and the correct use and implementation of procedures. The inspectors observed and verified that the deficiencies were adequately identified, discussed, and entered into the CAP, as appropriate. Documents reviewed are listed in the Attachment.
b. Findinqs No findings were identified.
.2 Biennial Review bv Reqional Specialist
a. Inspection Scope
The inspectors completed an in-office review of results of PSEG-administered annual operating tests and comprehensive written exams for 2010 on December 1, 2010. The inspection assessed whether pass rates were consistent with the guidance of IMC 0609, Appendix l, "Operator Requalification Human Performance Significance Determination Process". Documents reviewed are listed in the Attachment, The inspectors verified that:
.
Crew failure rate was less than 20 percent. (Crew failure rate was 0 percent)
.
Individual failure rate on the dynamic simulator test was less than or equal to 20 percent. (lndividual failure rate was 5 percent)
.
lndividual failure rate on the walkthrough test was less than or equal to 20 percent. (lndividualfailure rate was 0 percent)
.
Individual failure rate on the comprehensive written exam was less than or equal to 20 percent. (lndividualfailure rate was 2 percent)o Overall pass rate among individuals for all portions of the exam was greater than or equal to 75 percent. (Overall pass rate was 93 percent)b. Findinqs No findings were identified.
1R12 Maintenance Effectiveness
a. Inspection Scope
The inspectors completed two quarterly maintenance effectiveness inspection samples.
The inspectors reviewed performance monitoring and maintenance effectiveness issues for the two systems listed below. In addition, the inspectors reviewed the root cause investigation report for the 13 TDAFW pump spurious trips. The inspectors reviewed PSEG's process for monitoring equipment performance and assessing preventive maintenance effectiveness. The inspectors verified that systems and components were monitored in accordance with the Maintenance Rule Program requirements. The inspectors compared documented functionalfailure determinations and unavailability I
hours to those being tracked by PSEG to evaluate the effectiveness of PSEG's condition monitoring activities and to determine whether performance goals were being met. The inspectors reviewed applicable work orders (WOs), corrective action notifications, and preventive maintenance tasks. Documents reviewed are listed in the Attachment.
.
Unit 1 CCW pumps and HXs o Unit 2 control air (CA)b. Findinqs
Introduction:
A self-revealing NCV of Appendix B, Criterion V, "lnstructions, Procedures, and Drawings" was identified because of two unexpected trips of the turbine trip valve (1MS52) for the 13 TDAFW pump. Specifically, adjustments made to the overspeed linkage for the 13 TDAFW pump were not prescribed by documented procedures or drawings. These adjustments led to the increased sensitivity of the trip mechanism that resulted in the two unexpected trips.
Description:
The AFW system serves as a backup system for supplying feedwater to the secondary side of the steam generators at times when the main feedwater system is not available. The AFW system is equipped with one turbine driven and two motor driven auxiliary feed pumps, The turbine driven pump has a turbine trip valve (1MS52)associated with the pump. This valve can be shut remotely from the control room or by the turbine overspeed trip via a linkage from the turbine.
On April 26,2010, while PSEG was performing an inservice test on the 13 TDAFW pump, operators noted that the emergency trip lever would not stay in the reset condition after the turbine trip valve (1MS52) was reset. At that time, to correct the condition, PSEG adjusted the 13 TDAFW pump overspeed trip linkage, tested its operation, and reset the emergency trip lever- On June 24,2010, a similar condition developed that was also corrected in the same way, On July 7 , 2010, Unit 1 automatically tripped and the 13 TDAFW pump started and ran as designed. In accordance with emergency operating procedures, when the plant was verified stable, operators tripped the pump using the control room switch, reset 1MS52 in accordance with the system operating procedure, and restored the pump to a standby status. Approximately 36 minutes after the pump was restored, 1MS52 was again found unexpectedly tripped. PSEG concluded, based on a preliminary investigation, that the valve's trip solenoid needed to be replaced. At that time, PSEG replaced the solenoid and declared the 13 TDAFW pump operable on July 9, 2010, following a successful retest. However, on July 10,2010, the pump was again found tripped. This time, PSEG contacted the vendor for support and after its investigation concluded that a threaded rod positive stop on the back of the 1MS52 trip device head lever was preventing full engagement between the 1MS52 tappet nut and head lever. This caused the 1MS52 trip device to be overly sensitive and resulted in the unexpected trips. PSEG took action to correct the condition by raising the threaded positive stop so that it would not limit the head lever engagement and the 13 TDAFW pump was again declared operable on July 23, 2010.
Approximately two months later on September 2,2010, the 13 TDAFW pump overspeed mechanism again tripped unexpectedly coincident with the remote shutdown of the 13 TDAFW pump after the biweekly pump run. At this point, the pump vendor recommended that PSEG disassemble the 1MS52 head lever for inspection. From this inspection, PSEG determined that the tappet nut and head lever did not have the designed contact surface because the head lever surface was rounded. This caused less than adequate engagement between the head lever and the tappet nut, and as a result, also made the overspeed trip mechanism overly sensitive. PSEG repaired the head lever by weld build-up and machining to achieve a flat surface to improve the engagement between the head lever and the tappet nut. The 13 TDAFW pump was subsequently declared operable on September 4,2010.
PSEG determined, in their root cause analysis, that the adjustments made to the overspeed trip mechanism threaded positive stop for the 13 TDAFW pump were knowledge based and were not conducted using a procedure. There was no procedural guidance for when to conduct the adjustments, how to conduct the adjustments or where to set the threaded positive stop. As a result the adjustments to the mechanism made the overspeed trip overly sensitive and resulted in several spurious trips of the 1MS52 valve. In addition, over time, the adjustments and spurious trips contributed to the wear of the head lever and tappet nut that led to the trip of the 1MS52 valve on September 2, 2Q1Q, even after the threaded positive stop was removed. In summary, PSEG technicians were adjusting safety-related equipment without a procedure and this ultimately adversely affected the availability and reliability of the AFW system.
The threaded positive stop for the trip mechanism was installed by PSEG on the 13 TDAFW pump at some point after the initial installation of the pump, but was not depicted on any drawing and was not referenced in a procedure. As a permanent corrective action, PSEG removed the threaded rod from the 13 TDAFW pump head lever to restore the pump to original design configuration. As part of the extent-of-condition investigation, the same threaded rod was removed from the 23 TDAFW pump head lever. The 23 TDAFW trip mechanism also required a weld build-up repair to the head lever to restore the surface engagement between the tappet nut and head lever.
Analvsis: The inspectors determined that the adjustment of the 13 TDAFW pump overspeed linkage without the use of a procedure or drawing and the resulting unexpected 1MS52 trips and TDAFW unavailability time was a performance deficiency that was reasonably within PSEG's ability to foresee and prevent. 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. The trips of the 1MS52 valve and repairs to the overspeed trip mechanism resulted in 41 hours4.74537e-4 days <br />0.0114 hours <br />6.779101e-5 weeks <br />1.56005e-5 months <br /> of unavailability of the 13 TDAFW pump.
In accordance with NRC IMC 0609, Attachment 4, "Phase 1 - Initial Screening and Characterization of Findings," a Phase 1 SDP screening was performed and determined the finding was of very low safety significance (Green) because it was not a design or qualification deficiency, did not result in an actual loss of safety function, and was not potentially risk significant for external events. This finding had a cross-cutting aspect in the area of human performance, resources, because PSEG did not ensure that complete accurate and upto-date procedures and work packages were available and adequate to assure nuclear safety. Specifically, the procedure used to set the overspeed trip did not address adjustment of the threaded rod. (H.2(c).
Enforcement:
10 CFR 50, Appendix B, Criterion V, "lnstructions, Procedures, and Drawings," requires, in part, that activities affecting quality shall be prescribed by documented instructions, procedures, or drawings of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions, procedures, or drawings. Contrary to the above, the adjustment of the 13 TDAFW pump overspeed and turbine trip mechanism using the installed threaded rod was not prescribed by a documented instruction or procedure of a type appropriate to the circumstances. Specifically, operators were using the installed threaded rod to adjust the sensitivity of the trip mechanism so that the overspeed trip device would actuate each time the TDAFW pump was tripped using the trip solenoid from the control room.
The operator adjustment of the overspeed linkage using the threaded rod led to the spurious trips of the turbine trip mechanism and the 13 TDAFW pump unavailability time.
Because this violation was of very low safety significance (Green) and has been entered into PSEG's CAP as notification 20476129, this violation is being treated as a non-cited violation, consistent with Section 2.3.2 of the NRC Enforcement Policy. (NCV 0500027212010005-01, 13 Turbine Driven Auxiliary Feedwater Pump Trip Mechanism)
1R13 Maintenance Risk Assessments and Emerqent Work Control
a. Inspection Scope
The inspectors completed five maintenance risk assessment and emergent work control inspection samples. The inspectors reviewed the maintenance activities listed below to verify that the appropriate risk assessments were performed as specified by 10 CFR 50.65(a)(4) prior to removing equipment for work. The inspectors reviewed the applicable risk evaluations, work schedules, and control room logs for these configurations, PSEG's risk management actions were reviewed during shift turnover meetings, control room tours, and plant walkdowns. The inspectors also used PSEG's on-line risk monitor (Equipment OOS workstation) to gain insights into the risk associated with these plant configurations. The inspectors reviewed notifications documenting problems associated with risk assessments and emergent work evaluations. Documents reviewed are listed in the Attachment.
.
Unit 1, 1C EDG unplanned unavailability on October 1 1 o Unit 2,23 control area chiller OOS during mode ascension from mode 3 to mode 1 on October 18
.
Unit 1, 13 CFCU OOS on November 9 r Unit 1, 14 EDG and 16 SW pump OOS for planned maintenance on November 30
.
Unit 1, 1C EDG and offsite power line 5023 OOS for planned maintenance on December 16 b. Findinqs No findings were identified.
1R15 Operabilitv Evaluations
a. Inspection Scope
The inspectors completed five operability evaluation inspection samples. The inspectors reviewed the operability determinations for degraded or non-conforming conditions associated with:
.
Unit2,21 reactor coolant pump (RCP) undervoltage, pump did not trip; o Unit2,21 Sl pump past operability, oil leak;
.
Unit 1, 11 containment spray pump room cooler, high differential pressure; o Unit 1 and Unit 2, control area ventilation, in-leakage greater than expected value; and
.
Unit 1, 14 SW strainer motor, corrosion of cable stanchion.
The inspectors reviewed the technical adequacy of the operability determinations to ensure the conclusions were justified. The inspectors also walked down accessible equipment to corroborate the adequacy of PSEG's 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. Findinos No findings were identified.
1R18 Plant Modifications
a. Inspection Scope
The inspectors completed one plant modification inspection sample. The inspectors reviewed a temporary modification to the Unit 2, train B, reactor vessel level indication system (RVLIS). The modification cut and capped the train B capillary to stop a small leak at the high point fill valve tee. Train B RVLIS was already inoperable due to an internal bellows failure in the differential pressure transmitter. The inspectors verified that the design bases, licensing bases, and performance capability of the affected systems were not degraded by the temporary modification. The inspectors verified the new configuration was accurately reflected in the design documentation and the post modification testing was adequate to ensure the A train of the Unit 2 RVLIS would remain functional. The 10 CFR 50.59 screen associated with this temporary modification was also reviewed. Documents reviewed are listed in the Attachment.
b. Findinqs No findings were identified.
1R19 Post-Maintenance Testino
a. Inspection Scope
The inspectors completed four post-maintenance testing (PMT) inspection samples.
The inspectors observed portions of and/or reviewed the PMT results for the maintenance activities listed below. The inspectors verified that the effect of testing on the plant was adequately addressed by control room and engineering personnel; testing was adequate for the maintenance performed; acceptance criteria were clear, demonstrated operational readiness and were consistent with design and licensing basis documentation; test instrumentation calibration was current and the appropriate range and accuracy for the application; tests were performed, as written, with applicable prerequisites satisfied; and equipment was returned to an operational status and ready to perform its safety function. Documents reviewed are listed in the Attachment.
.
WO 60092859, planned extent of condition inspection on 2A EDG potential transformer drawer r WO 30094412, emergent corrective maintenance on 13SW72, 13 CFCU SW outlet valve (air operated valve)
.
WO 30184881, planned maintenance on 14 EDG
.
WO 501351 19, planned maintenance on 1C EDG b. Findinqs No findings were identified.
1R22 Surveillance Testing (71111
.22 - 6 samples)
a. lnspection Scope The inspectors completed six surveillance testing inspection samples. The inspectors observed portions of and/or reviewed results for the surveillance tests listed below to verify, as appropriate, whether the applicable system requirements for operability were adequately incorporated into the procedures and that test acceptance criteria were consistent with procedure requirements, the technical specification (TS) requirements, the updated final safety analysis report (UFSAR), and American Society of Mechanical Engineers (ASME) Section Xl for pump and valve testing. Documents reviewed are listed in the Attachment.
.
51.OP-ST.RHR-0002, Inservice Testing - 12 Residual Heat Removal (RHR) Pump
.
51.lC-ST.SSP-0005, Train B RX Trip and Bypass Breaker P-4 Permissive Test
.
S2.OP-ST.SJ-0001, lnservice Testing - 21 Sl Pump
.
52.OP-ST.RHR-0002,22 RHR Pump Quarterly Test
.
S2.OP-ST.RC-0008, Unit 2 Reactor Coolant System Leak Rate Test
.
52.OP-PT.AF-0003, 23 AFW Pump Periodic Run b. Findinqs No findings were identified.
RADIATION SAFETY
Cornerstone: Radiation Safety - Public and Occupational
2RS1 Radiolosical Hazard Assessment and Exposure Controls
a. Inspection Scope
I nstructions to Workers The inspectors verified that containers holding nonexempt licensed radioactive materials that could cause unplanned or inadvertent exposure to workers were appropriately labeled and controlled.
The inspectors reviewed radiation work permits (RWPs) used to access high radiation areas and identify what work control instructions or control barriers had been specified.
The inspectors verified that allowable stay times or permissible dose for radiologically significant work under each RWP was clearly identified. The inspectors verified that electronic personal dosimeter (EPD) alarm set points were in conformance with survey indications and plant policy. The inspectors selected occurrences where a worker's EPD noticeably malfunctioned or alarmed. The inspectors verified that workers responded appropriately to the off-normal condition. The inspectors verified that the issue was included in the CAP and dose evaluations were conducted as appropriate.
Contamination and Radioactive Material Control The inspectors observed several locations where PSEG monitors potentially contaminated material leaving the radiological controlled area and inspected the methods used for control, survey, and release from these areas. The inspectors verified that the radiation monitoring instrumentation had appropriate sensitivity for the type(s) of radiation present.
The inspectors reviewed PSEG's criteria for the survey and release of potentially contaminated material. The inspectors verified that there was guidance on how to respond to an alarm that indicated the presence of licensed radioactive material.
The inspectors reviewed PSEG's procedures and records to verify that the radiation detection instrumentation was used at its typical sensitivity level based on appropriate counting parameters.
The inspectors selected sealed sources from PSEG's inventory records that presented the greatest radiological risk. The inspectors verified that sources are accounted for and had been verified to be intact.
The inspectors verified that any transactions involving nationally tracked sources were reported in accordance with 10 CFR 20.2207.
Radiation Protection Technician Proficiencv During job performance observations, the inspectors observed the performance of the radiation protection technician with respect to radiation protection work requirements.
The inspectors determined that technicians were aware of the radiological conditions and RWP controls/limits in their workplace and that their performance was consistent with their training and qualifications with respect to the radiological hazards and work activities.
The inspectors reviewed radiological problem reports submitted since the last inspection where the cause of the event was found to be radiation protection technician error. The inspectors determined that there was no observable pattern traceable to a similar cause.
The inspectors determined that this perspective matched the corrective action approach taken by PSEG to resolve the reported problems.
Problem ldentification and Resolution The inspectors verified that problems associated with radiation monitoring and exposure control were being identified by PSEG at an appropriate threshold and were properly addressed for resolution in PSEG's CAP. In addition to the above, the inspectors verified the appropriateness of the corrective actions for a selected sample of problems documented by PSEG that involved radiation monitoring and exposure controls. The inspectors determined that PSEG was assessing the applicability of operating experience to their plants.
b. Findinos No findings were identified.
2RSs Radiation Monitorinq lnstrumentation (71124.05)
a. Inspection Scope
Walkdowns and Observations The inspectors walked down five effluent radiation monitoring systems, including liquid and gaseous systems. The inspectors verified that effluent/process monitor configurations align with offsite dose calculation manual descriptions.
Laboratorv nstrumentation I
The inspector selected one of each type of laboratory analytical instruments used for radiological analyses. The inspector verified that daily performance checks and calibration data indicated that the frequency of the calibration was adequate and no indications of degraded instrument performance were found.
Problem ldentification and Resolution The inspectors verified that problems associated with radiation monitoring instrumentation were identified by PSEG at an appropriate threshold and were properly addressed for resolution in PSEG's CAP.
Findinqs No findings were identified.
OTHER ACTIVITIES
4OA1 Performance Indicator (Pl) Verification
a. lnspection Scope The inspectors reviewed PSEG submittals for the Unit 1 and Unit 2 Mitigating Systems cornerstone Pls discussed below. To verify the accuracy of the Pl data reported during this period the data was compared to the Pl definition and guidance contained in Nuclear Energy Institute 99-02, "Regulatory Assessment Performance Indicator Guideline,"
Revision 5.
Cornerstone: Mitioatinq Svstems
. Unit 1 and Unit 2 Emergency AC Power System
. Unit 1 and Unit 2 High Pressure Safety Injection System The inspectors reviewed the consolidated data entry Pl derivation reports for the unavailability and unreliability indexes for the monitored systems; the monitored component demands and demand failure data for the monitored systems; and the train and system unavailability data for the monitored systems. The inspectors verified the accuracy of the data by comparing it to CAP records, control room operator logs, maintenance rule performance and scope reports, system performance/health reports, the equipmenUoperability issues database, the site operating history database, key Pl summary records, and operating data reports.
Cornerstone: Radiation Safetv
. Occupational Exposure Control Effectiveness
. Radiological Etfluent Technical Specifications (RETS)/Offsite Dose Calculation Manual (ODCM) Radiological Effluent The inspectors reviewed a listing of action reports for the period January 1,2010, through October 1, 2010, for issues related to the occupational Occupational Exposure Control Effectiveness Pl that measures non-conformances with high radiation areas greater than 1 R/hr and unplanned personnel exposures greater than 100 mrem total effective dose equivalent (TEDE), 5 rem skin dose equivalent (SDE), 1.5 rem lens dose equivalent (LDE), or 100 mrem to the unborn child. The inspectors determined if any of these Pl events involved dose rates >25 FVhr at 30 centimeters or >500 R/hr at 1 meter.
lf so, the inspectors determined what barriers had failed and if there were any barriers left to prevent personnel access. For unintended exposures (>100 mrem TEDE or >5 rem SDE or >1.5 rem LDE), the inspectors determined if there were any overexposures or substantial potential for overexposure. The inspector determined that no Pl events had occurred during the assessment period.
The inspectors reviewed a listing of action reports for the period January 1,2010, through October 1,2Q10, for issues related to the RETS/ODCM Radiological Effluent Pl that measures radiological effluent release occurrences per site that exceed 1.5 mrem/qtr whole body or 5 mrem/qtr organ dose for liquid effluents; or 5 mrads/qtr gamma air dose, 10 mrads/qtr beta air dose, or 7
.5 mrems/qtr organ doses from l-131 , l-
133, H-3, and particulates for gaseous effluents.
b. Findinqs No findings were identified.
4c.42 ldentification and Resolution of Problems (71152 - 2 annual samples; 1 trend sample)
,1 Review of ltems Entered into the Corrective Action Proqram As required by Inspection Procedure 71152, "ldentification 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 CAP. This was accomplished by reviewing the description of each new notification and attending daily management review committee meetings. Documents reviewed are listed in the Attachment.
.2 Semi-Annual Review to ldentifv Trends
a. Inspection Scope
As required by Inspection Procedure 71152, "ldentification and Resolution of Problems,"
the inspectors performed a review of PSEG's CAP and associated documents to identify trends that could indicate the existence of a more significant safety issue. The inspectors' review was focused on repetitive equipment and corrective maintenance issues, but also considered the results of the daily inspector CAP item screening discussed in Section 4OA2.1. The review included issues documented in system health reports, corrective maintenance WOs, component status reports, site monthly meeting reports, and maintenance rule assessments. The inspectors'review nominally considered the six-month period of June 1, 2010 through November 30, 2010, although some examples expanded beyond those dates when the scope of the trend warranted.
The inspectors compared and contrasted their results with the results contained in PSEG's latest integrated quarterly assessment report. Corrective actions associated with a sample of the issues identified in PSEG's trend report were reviewed for adequacy. The inspectors also evaluated the trend report specified in SPP-3.1, "Corrective Action Program." Documents reviewed are listed in the Attachment.
b. Assessment and Observations No findings were identified.
During this review the inspection noted a negative trend in equipment reliability. This conclusion was supported by three observations. First, there continues to be a significant number of radiation monitor failures throughout the plants. Some of the radiation monitors have been replaced or upgraded, yet the number of failures is still significant. Compensatory measures are implemented as necessary when the radiation monitors are not in service. This issue is being addressed specifically in the Equipment Reliability Excellence Plan. Second, there have been five plant trips in 201Q, with three of these trips occurring in the second half of the year. This represents an increasing trend, because there were no plant trips during calendar year 2009. Four of the five plant trips were due to failure of equipment important to safety. There were also trips on both units caused by problems with the main generator voltage regulator, and root cause evaluations have been performed for each of these trips to determine the causes and appropriate corrective actions. In response to the increase in reactor trips, PSEG formed a Site Equipment Reliability High lmpact Team, tasked with identifying ways to reduce the number of plant trips and unplanned power reductions on site. Third, there were repeat instances of CA dryers with issues resulting in elevated dew point readings.
CA that is not sufficiently dry can result in erratic operation of air operated controls, especially during cold weather. PSEG has addressed these issues through their corrective action process.
Station management is aware of these issues and taking actions to mitigate the trend through more effective preventative maintenance, improved troubleshooting and increased sensitivity to repeat equipment failures. More specifically, PSEG is addressing equipment reliability using action plans intended to reduce critical component equipment failures through improved preventative maintenance and long term actions to replace obsolete or chronically unreliable equipment. For example, the R13 CFCU service water effluent radiation monitors have had their electronics upgraded as well as reductions in the air entrainment in the sample flow source. Engineering and maintenance departments are individually working to improve troubleshooting and technical rigor, and the obsolete Unit 1 automatic voltage regulator is planned for replacement during the fall 2011 RFO. The Site Equipment Reliability High lmpact Team has identified single point vulnerabilities in the main feed and condensate systems, and is developing recommendations to address these issues. Operations department is raising the sensitivity to control air dryer issues, and driving prompt repairs of this equipment when required.
Annual Sample: Triennial Fire Protection Corrective Actions a. lnspection Scope The inspectors reviewed PSEG's actions to investigate and identify the cause of the Green NCV for failure to evaluate a single spurious operation of a Sl signal during a main control room fire and its impact on the ability to achieve and maintain hot standby conditions. This issue was identified as an NCV (0500027l 05000311/2009006-01, Failure to Evaluate Spurious Operation of Safety Injection Signal) in lR 05000272, 05000311/2009006. The inspectors reviewed PSEG's action towards identification and completion of corrective actions. The inspectors reviewed PSEG procedures, calculations, notifications, orders, corrective actions, and root cause evaluations to understand the analysis to address the potentialfor spurious Sl signal during a postulated control room fire, as well as the identification, evaluation, and corrective actions associated with the analysis. System engineers and other PSEG staff were interviewed to gain additional insights on the corrective actions.
Findinqs & Observations No findings were identified.
The inspectors found that PSEG appropriately identified the failure to evaluate the impact of single spurious operation of Sl signal during a main control room fire and entered the issue into the CAP. PSEG's root cause investigation determined the cause of failure to evaluate a single spurious operation of a Sl signal to be associated with incorrect risk perception and improper management of engineering resources. The failure to evaluate the single spurious operation in a timely manner was caused by incorrect evaluation of the issue as a multiple spurious operation, or beyond design basis issue, and a lack of engineering resources with the specific skill set necessary for the evaluation of a single spurious operations scenario. As corrective action, PSEG contracted the appropriate engineering services to complete the single spurious operation evaluation. lnspectors determined that the evaluations of degraded conditions were thorough and included considerations for extent of condition. The inspectors reviewed PSEG's corrective actions and determined that they were appropriate to adequately address identified deficiencies.
.4 Annual Sample: Pressurizer Heater Motor Control Center (MCC) Heatinq
Inspection Scope The inspectors reviewed PSEG's actions to evaluate and correct higher than expected temperature conditions in the Unit 2 replacement pressurizer heater MCCs 2SWGR2EPX and 2SWGR2GPX. The inspectors reviewed the TSs, the UFSAR, vendor documents, notifications, orders, corrective actions, and causal evaluations to understand the equipment functions and operational history, as well as the identification, evaluation, and corrective actions associated with the MCC high temperatures. The inspectors interviewed design and system engineers to gain additional insights on the issue and performed a walkdown of the affected MCCs to assess the current operating conditions of the equipment. Documents reviewed are listed in the Attachment.
Findinqs and Observations No findings were identified.
The inspectors found that PSEG appropriately identified the overheating condition associated with the replacement MCCs and entered the issue into the CAP in a timely manner. PSEG's investigation of the issue included an evaluation of the sources of the heat and also evaluated the components within the MCC to determine the acceptable operating temperatures of the components. A plant modification was implemented to replace the existing access doors on the MCCs with doors that contained air vents to facilitate dissipation of the expected heat generated within the MCCs. Prior to installation of the replacement doors, PSEG had the equipment vendor construct a cubical that replicates conditions that would exist within the MCCs and perform a test to verify the vents would ensure internal ambient temperatures would remain acceptable under design conditions.
The inspectors determined that the evaluations of degraded conditions were thorough and included appropriate considerations for extent of condition. The inspectors reviewed PSEG's corrective actions and determined that they were appropriate to adequately address identified deficiencies, 4043 Event Follow-up (71153 - 3 samples)
.1 (Closed) Licensee Event Report (LER) 05000272/2010-004-00. Technical Specification
3.0.4.b Non-Compliance ln September 2Q10, Salem Unit 1 was in the process of an initial campaign to move
'aged' irradiated fuel from the Spent Fuel Pool (SFP) to a Dry Cask Storage facility. On September 20 at 4:07 AM, the 13 Chiller was tagged OOS for scheduled maintenance.
At 8:49 PM, Unit 1 Control Room supervisor authorized irradiated fuel movement from the Unit 1 SFP to support dry cask storage. Movement of irradiated fuel commenced and was completed without meeting the TS 3.0.4.b requirement to perform a risk assessment due to the inoperable chiller. TS 3,7.10 requires allthree chillers to be operable for the movement of irradiated fuel. On September 29, an independent review by Operations in preparation for the next cask loading questioned whether movement of irradiated fuel should have commenced without the performance of a TS 3.0.4.b risk assessment with the 13 chiller OOS. The TS non-compliance was identified as a result of this review.
PSEG determined that the apparent cause was a failure to recognize TS 3.0.4.b applicability when a specified condition of the TS applicability was entered and inattention to detail during the evaluation of the effects of OOS equipment when reviewing procedural controls for movement of irradiated fuel. Corrective actions included personnel accountability, completion of risk assessment for remaining dry cask storage activities, and a procedure revision. PSEG's risk assessment concluded that the risk of loading fuel in the canister with one of the three control area chillers out of service was small. The movement of spent fuel was resumed following the completion of the risk assessment. The inspectors concluded that this TS violation was an administrative error, and would not have impacted the decision to commence fuel movement. The failure to comply with TS 3.0.4.b was a violation of minor significance that is not subject to enforcement action in accordance with the NRC's Enforcement Policy. This LER is closed.
.2 Plant Trip Followinq Generator Protection Turbine Trip
a. Inspection Scope
On October 15, Unit 1 automatically tripped following a trip of the main turbine. The cause of the turbine trip was actuation of the loss of field relay, which provides protection for the main generator. The inspectors responded to the plant to observe control room activities following the trip and to assess plant conditions. The inspectors reviewed the sequence of events report, independently reviewed pre trip and post trip conditions for potential impacts on safety related equipment, and reviewed PSEG's post trip report prior to restart.
b. Findinqs No findings were identified.
.3 Plant Trip Following Reactor Coolant Protection Bus Undervoltaoe
a. lnspection Scope On October 17, Unit 2 automatically tripped in response to bus undervoltage for the 21 through 24 RCPs. At the time, the RCPs were supplied power from the normal on-line source, the Unit 2 auxiliary power transformer that is directly powered from the Unit 2 main generator. The main generator voltage regulator was in manual control and operators were in the process of transferring it to automatic control. During this transfer, a loss of excitation occurred. The inspectors responded to the control room to observe operator actions in response to the trip and to assess plant conditions. The inspectors reviewed the sequence of events report, reviewed the pre trip and post trip conditions for potential impacts on safety related equipment, and reviewed PSEG's post trip report prior to restart. The inspectors verified that grid stability was not a common cause as an initiator for the Unit 1 and Unit 2 trips.
b. Findinqs No findings were identified.
40A5 Other Activities
.1 Operation of an Independent Spent Fuel Storaoe Installation (lSFSl) at Ooeratinq Plants
(60855.1)
a. Inspection Scope
The inspectors verified by direct observation and independent evaluation that PSEG had performed loading activities at the ISFSI in a safe manner and in compliance with applicable procedures. The inspectors toured the lSFSl, observed the performance of radiological surveys, and reviewed radiological surveys performed during the past twelve months.
b. Findinqs No findings were identified.
4OAO Meetinqs. Includinq Exit The inspectors presented the inspection results to Mr. C. Fricker and other members of PSEG management at the conclusion of the inspection on January 6,2011. The inspectors asked PSEG whether any materials examined during the inspection were proprietary. No proprietary information was identified.
ATTACHMENT:
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee personnel
- C. Fricker, Site Vice President
- E. Eilola, Plant Manager
- R. DeSanctis, Maintenance Director
- L. Rajkowski, Engineering Director
- J. Garecht, Operations Director
- R. Gary, Radiation Protection Manager
- J. Patel, Safe Shutdown Engineer
- H. Berrick, Regulatory Assurance
- E. Villar, Regulatory Assurance
- T. Giles, lSl Program Manager
- G. Marshall, Operations Training Manager
- B. Thomas, Senior Compliance Engineer
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Closed
- 0500027212010-004-00 LER Technical Specification 3.0.4.b Non-
Compliance (Section 4OA3.1 )
Open/Closed
- 0500027212010005-01 NCV 13 Turbine Driven Auxiliary Feedwater Pump Trip Mechanism (Section 1R12)