IR 05000272/2010004
| ML102980181 | |
| Person / Time | |
|---|---|
| Site: | Salem  |
| Issue date: | 10/25/2010 |
| From: | Arthur Burritt Reactor Projects Branch 3 |
| To: | Joyce T Public Service Enterprise Group |
| burritt al | |
| References | |
| IR-10-004 | |
| Download: ML102980181 (35) | |
Text
UNITED STATES NUCLEAR REGULAtORY COMMISSION
REGION I
475 ALLENDALE ROAD KING OF PRUSSIA, PA 19406-1415 October 25, 2010 Mr. Thomas P. Joyce President and Chief Nuclear Officer PSEG Nuclear LLC ~ N09 P.O. Box :236 Hancock'H Bridge, NJ 08038 SUB~IECT: SALEM NUCLEAR GENERATING STATION, UNIT NOS. 1 AND 2 NRC INTEGRATED INSPECTION REPORT 05000272/2010004 and 05000311/2010004
Dear Mr.*Joyce:
On September 30,2010, 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 the inspection results discussed on October 7, 2010, 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 your license.
The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel..
Based on the results of this inspection, no findings of significance were identified. However, two licensee~identified violations that were determined to be of very low safety significance are listed in this report. The NRC is treating these violations as non-cited violations (NCVs) consistent with Secti()n 2.3.2.a of the NRC Enforcement Policy because of the very low safety significance of the violcltions and because they are entered into your corrective action program (CAP). If you contest thE~se NCVs, 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, A TIN: Document Control De~sk, Washington, DC 20555-0001; with copies to the Regional Administrator, Region I; the Directclr, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at the Salem Nuclear Generatin~~ Station.
In accordance with 10 Code of Federal Regulations (CFR) 2.390 of the NRC's "Rules of Practice," i3 copy of this letter, its enclosure, and your response (if any) will be available electronic8111y for public inspection in the NRC Public Document Room or from the Publicly
T.Joyce 2 Available Hecords (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).
Arthur L. Burritt, Chief Projects Branch 3 Division of Reactor Projects Docket Nos: 50-272; 50-311 License Nos: DPR-70; DPR-75
Enclosure:
Inspection Report 0500027212010004 and 05000311/2010004 w/Attachment: Supplemental Information co w/encl: Distribution via ListServ
T. Joyce 2 Available Records (PARS) component of NRC's document system (ADAMS). ADAMS is a
REGION I==
Docket Nos: 50-272, 50-311 License Nos: DPR-70, DPR-75 Report No: 05000272/2010004 and 05000311/2010004 Licensee: PSEG Nuclear LLC (PSEG)
Facility: Salem Nuclear Generating Station, Unit Nos. 1 and 2 Location: P.O. Box 236 Hancocks Bridge, NJ 08038 Dates: July 1, 2010 through September 30, 2010 Inspectors: D. Schroeder, Senior Resident Inspector S. Ibarrola, Acting Resident Inspector J. Ayala, Acting Resident Inspector E. Torres, Acting Resident Inspector E. Burket, Reactor Inspector J. Furia, Senior Health Physicist Approved By: Arthur L. Burritt, Chief Projects Branch 3 Division of Reactor Projects Enclosure
SUMMARY OF FINDINGS
IR 050002 J2I20 10004, 05000311/2010004; 07/01/2010 - 09/30/2010; Salem Nuclear
Generating Station Unit Nos. 1 and 2; Routine Integrated Inspection Report.
The report covered a three-month period of inspection by resident inspectors, and announced inspections by a regional radiation specialist and reactor engineers. 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.
No findings of significance were identified.
Other Findings
Two violations of very low safety significance, which were identified by PSEG, have been reviewed by the inspectors. Corrective actions taken or planned by PSEG have been entered into PSEG's CAP. These violations and their corrective action tracking numbers are listed in Section 40A7 of this report.
REPORT DETAILS
Summary ()f Plant Status Salem Nuclear Generating Station Unit No. 1 (Unit 1) began the period at full power. On July 7, Unit 1 automatically tripped following a fault on the B main power transformer (MPT). Unit 1 was synchronized to the grid on July 24 and full power was reached on July 25. On September 17, after operators isolated bleed steam valve, 12BS22, due to an internal steam leak, operators reduced power to 98 percent to comply with engineering established main turbine operating limits. Unit 1 remained at 98 percent power for the remainder of the inspection period.
Salem Nuclear Generating Station Unit No.2 (Unit 2) began the period at full power. Unit 2 remained at or near full power for the duration of the inspection period.
REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, and Emergency PrE~paredness
1R01 Adverse Weather Protection
.1 Evaluate Readiness for Seasonal Extreme Weather Conditions
a. Inspection Scope
The inspectors completed one adverse weather protection sample to evaluate readiness for seasonal extreme weather conditions. The inspectors reviewed PSEG's preparation and protection of risk significant systems at Unit 1 and Unit 2 during hot weather conditions between July 6 and July 7,2010. The inspectors evaluated PSEG's implementation of summer readiness procedures and compensatory measures for extreme hot weather that included ultimate heat sink temperatures above 84°F and ambient air temperatures above 100°F. The inspectors walked down risk-significant strlJctures, systems, and components (SSCs) to ensure that weather related conditions did not adversely impact sse operability. In addition, the inspectors assessed the condition of balance of plant equipment with the potential to initiate plant-level transients.
The inspectors performed detailed walkdowns of the service water (SW) intake, emergency diesel generators (EOGs), vital switchgear rooms, the gas turbine generator (GTG), main and unit auxiliary transformers, component cooling water (CCW) heat exchangers, the main turbines and generators, and the station air compressors.
Th,e inspectors observed portions of GTG performance testing from the control room and GTG local control panel. The inspectors also reviewed PSEG corrective action notifications to ensure that PSEG appropriately identified and resolved weather related problems. The documents reviewed are listed in the Attachment.
b. Findings
No findings were identified .
.2 Evaluate Readiness to Cope with External Flooding
a. Inspection Scope
I The inspectors completed one adverse weather protection sample to evaluate readiness for external flooding. The inspectors reviewed PSEG's preparations and compensatory measures for severe weather conditions that posed a risk of flooding during the week of August 23, 2010. The inspectors interviewed operations and engineering personnel regarding the actions taken to prepare for the impending severe weather and walked down risk significant systems to independently assess the adequacy of PSEG's preparations. Specifically, the inspectors reviewed the condition of the service water intake structure (SWIS) external flood protection. The inspectors verified that degraded conditions with the potential to impact safety"related components and systems were reported in the CAP. Corrective action notifications written for degraded conditions were reviewed to ensure that operability of components in the SWIS was not impacted. For those areas where operator actions were credited for maintaining safety-related system operability during a flooding event, the inspectors also verified that the procedures used to direct those actions could be fully implemented during the event. Documents reviewed are listed in the Attachment.
b. Findings
No findings were identified.
1R04 Eguipment Alignment (71111.04 - 4 samples;
==71111.04S - 1 sample)
.1 Partial Walkdown
a. Inspection Scope
==
The inspectors completed four 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 2,28 and 2C EDG with 2A EDG ODS on 'July 29
- Unit 2, 21 and 23 chillers with 22 chiller DOS on September 20
b. Findings
No findings were identified.
.2 Complete Walkdown
a. Inspection Scope
The inspectors conducted one complete walkdown inspection sample of the Unit 1 auxiliary feedwater (AFW) system. The inspectors independently verified the alignment and status of AFW motor-driven pumps and valves electrical power, labeling, hangers and supports, and associated support systems. The walkdown also included verification of valve pesitiens, evaluation of system piping and equipment te verify pipe hangers were in satisfactery condition, oil reservoir levels were nermal, pump rIOems and pipe chases were adequately ventilated, system parameters were within established ranges, and equipment deficiencies were appropriately identified. The inspectors interviewed engineering personnel and reviewed cerrective action evaluations associated with the system to determine whether equipment alignment preblems were identified and apprepriately resolved. Decuments reviewed are listed in the Attachment.
b. Findings
NIt) findings were identified.
1R05 Fire Protection (71111.050 - 6 samples)
.1 Fire Pretectien - Tours
a. Inspection Scope
The inspectors cempleted six quarterly fire protection inspectien samples. The inspecters walked dewn the systems listed below to assess the material condition and operational status of fire protectien features. The inspectors verified that combustibles and ignition sources were contrelled 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 out of service, degraded, or inoperable fire protection equipment were implemented in accordance with PSEG's fire plan. Documents reviewed are listed in the
.
- Unit 2, 4160V switchgear rooms, 64' elevation;
- Unit 1 and Unit 2, AFW pumps area, 84' elevation;
- Unit 1 and Unit 2, SW intake structure, 92' & 112' elevations; and
- Unit 2, chemical and volume control system (CVCS) hold-up tank area, 64' elevation.
b. Findings
No findings were identified.
'I
R06 Flood Protectien Measures
.1 Internal Flooding
a. Inspection Scope
The inspectors completed one internal flooding area inspection sample. The inspectors eVi:lluated flood protection measures for the Unit 1 and Unit 2 SW pump bays. The inspectors interviewed engineering personnel and walked down the areas to assess operational readiness of various features in place to protect redundant safety-related components. These features included plant drains, watertight doors, sump pumps, and wall penetration seals. The inspectors also reviewed the flooding penetration seal inspections. operator logs, abnormal procedures, and corrective action notifications associated with flood protection measures. Documents reviewed are listed in the
.
b. Findings
No findings were identified .
.2 Underground Bunkers/Manholes Subiect to Flooding
a. Inspection Scope
The inspectors completed one underground cable inspection sample. The inspectors evaluated the condition of safety-related cables located in underground bunkers and manholes. The inspectors interviewed engineering personnel and examined photographic evidence of conditions in manhole vault MH-SWI-1. The inspectors verified that safety-related cables were not SUbmerged in water, the integrity of the cables, the condition of cable support structures, and the ability to dewater these structures. The inspectors noted that PSEG had recently instituted a cable aging management program at the site. Documents reviewed are listed in the Attachment.
b. Findings
No findings were identified.
1R11 Licensed Operator Regualification Program (71111.11 Q - 1 sample)
.1 Re~qualification
Activities Review by Resident Staff
a. Inspection Scope
The inspectors completed one quarterly licensed operator requalification program inspection sample. Specifically, the inspectors observed a scenario administered to a single crew during a training drill on September 14, 2010. The scenario included a partial loss of offsite power, a loss of turbine generator stator cooling water that resulted in a reactor trip, and a loss of coolant accident. 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 also 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. Findings
No findings were identified.
1R12 Maintenance Effectiveness
a. Inspection Scope
ThE~ inspectors completed three quarterly maintenance effectiveness inspection samples. The inspectors reviewed pelformance monitoring and maintenance effectiveness issues 'for three components/systems listed below. The inspectors reviewed PSEG's process for monitoring equipment pelformance 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 functional failure determinations and unavailability 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 (Was), corrective action notifications, and preventive maintenance tasks. The documents reviewed are IiStl3d in the Attachment.
- 13 and 23 positive displacement charging pumps
- Unit 1 AFW pumps
- Unit 3 GTG
b. Findings
No findings were identified.
1R13 Maintenance Risk Assessments and Emergent Work Control
a. Inspection Scope
The inspectors completed six 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 pelformed 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, 13 AFW pump unavailability from July 7 to July 9 during Unit 2 forced outage
- Unit 1 and Unit 2, control area ventilation (CAV) in maintenance mode on July 28
- Unit 2, 2A EDG 008 on August 23
- Unit 1, 13 AFW emergent repairs due to trip throttle valve overspeed tripped after a remote trip of MS-52 from the control room on September 3
- Unit 2, 23 control area supply fan OOS for planned maintenance on September 7
b. Findings
No findings were identified.
1R 15 Operability Evaluations (71111.15 - 5 samples)
a. Inspection Scope
The inspectors completed five operability evaluation inspection samples. The inspectors revi:ewed the operability determinations for degraded or non-conforming conditions associated with:
- Unit 1, 1CV284 reactor coolant pump seal return isolation valve with inactive boron leak on weld;
- Unit 2, 22 residual heat removal (RHR) pump room cooler with 22 SW inlet valve (22SW153) failed in open position;
- Unit 2, 2A EDG failure to shutdown at the end of a routine surveillance;
- Unit 2, 22BF22 feedwater containment isolation valve internal noise; and
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.
No findings were identified.
R18 Plant Modifications
.1 Temporary Modifications
a. Inspection Scope
The inspectors completed two plant modification inspection samples by reviewing the key characteristics associated with the two temporary plant modifications listed below.
Th<<9 inspectors verified that the design bases, licensing bases, and performance capability of the affected'systems were not degraded by the temporary modifications.
The license amendment associated with the Technical Specification (TS) change for the 2C battery was also reviewed. Other documents reviewed for these samples are listed in the Attachment.
- Unit 1, 11 & 12 AFW pumps lifted leads .
- Unit 2, 2C battery temporary installation
b. Findings
A violation of very low safety significance (Green) was identified by PSEG and is documented in Section 40A7.
1R 19 Post-Maintenance Testing (71111
.19 - 7 samples)
a.
InslDection Scope The inspectors completed seven 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 had current calibrations 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.
- WOs 60091111 and 60091124, 13 turbine-driven AFW pump trip solenoid and overspeed trip mechanism head lever following emergent corrective maintenance
- WO 60090467. 23 CCW pump inboard and outboard pump seals replacement
- WO 60091466. 2A EDG PanAlarm power supply replacement
- WO 60081294. 2SJ2. charging pump suction valve, thermal overload replacement
- WO 60092089, 22 control area chiller compressor replacement
- WO 60087957, 2C 125 Vdc temporary battery
- WO 30197598,13 AFW pump following head lever maintenance
b. Findings
No findings were identified.
1
R20 Refueling and Other Outage Activities
a. Inspection Scope
Plant Trip Following Main Generator Trip_ On July 7, 2010, Unit 1 tripped following a main generator trip related to a failure of the B phase of the MPT. PSEG conducted a forced outage from July 7,2010, through July 24.2010, to repair the MPT, replace the 1CV284, and perform additional maintenance activities. During the outage, the inspectors monitored or observed the activities listed below to verify PSEG controls over the outage activities. The documents reviewed are listed in the Attachment.
- Portions of the shutdown and cool down processes
- Outage risk management
- Decay heat removal operations
- Configuration management, including maintenance of defense in depth
- Status and configuration of electrical systems and switchyard activities to ensure that TSswere met
- Walkdown of selected containment areas to check for unidentified leakage or other (liscrepant conditions
- Personnel fatigue management controls
b. Findings
No findings were identified.
1R22 Surveillance Testing
a. Inspection Scope
The inspectors completed five 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 TS requirements, the updated final safety analysis report (UFSAR), and American Society of Mechanical Engineers (ASME)
Section XI for pump and valve testing. Documents reviewed are listed in the
.
- S2.0P-ST.DG-0001, 2A Diesel Generator Surveillance Test
- S2.0P-ST.SJ-0001, Inservice Testing - 21 Safety Injection Pump
- S1.IC-FT.RCP-0023, 1PT-474 Pressurizer Pressure Protection Channel IV Functional Test
- S2.0P-ST.RHR-0002, Inservice Testing - 22 RHR Pump
- S2.0P-ST.RHR-0002, RHR Discharge Check Valve 22RH8 Forward and Reverse Flow Test
b. Findings
No findings were identified.
RADIATION SAFETY
Cornerstone: Radiation Safety - Public and Occupational
2RS1 Radiological Hazard Assessment and Exposure Controls
a. Inspection Scope
Inspection Planning
The inspectors reviewed PSEG performance indicators for the Occupational Exposure Cornerstone for follow-up. The inspectors reviewed the results of radiation protection program audits (e.g., PSEG's quality assurance audits or other independent audits).
The inspectors reviewed reports of operational occurrences related to occupational radiation safety since the last inspection.
The inspectors reviewed Prompt Investigation Report - Low Dose and Dose Rate Alarm*
Received During Radiography (notification 20467421) regarding an event on June 16, 2010, during radiography operations in the Unit 2 mechanical penetration service water room. During this activity, a locked high radiation event took place (dose rates in excess of 1000 millirem per hour measured at 30 centimeters from the source of radiation).
PSEG has reported this event under the occupational exposure cornerstone and the associated performance indicator.
The inspectors observed radiography operations conducted in the Unit 1 containment on July 19-20,2010, and verified that PSEG had implemented corrective actions from the June 16, 2010, event and that these corrective actions were effective.
Ris,k-Significant High Radiation Area (HRA) and Very High Radiation Area (VHRA)
Controls The inspectors discussed with the Radiation Protection Manager (RPM) the controls and procedures for high-risk HRAs and VHRAs. The inspectors verified that any changes to PSEG procedures did not substantially reduce the effectiveness and level of worker protection.
The inspectors discussed with first-line health physics supervisors the controls in place for special areas that have the potential to become VHRAs during certain plant opl9rations. The inspectors verified that PSEG controls for all VHRAs, and areas with the potential to become a VHRA, ensured that unauthorized individuals were not able to gain access to the VHRA.
Radiation Worker Performance During job performance observations. the inspectors observed radiation worker performance with respect to stated radiation protection work requirements. The inspectors determined that workers were aware of the significant radiological conditions in their workplace, radiation work permit controls/limits were in place, and that their performance reflected the level of radiological hazards present.
The inspectors reviewed radiological problem reports since the last inspection that found thE~ cause ofthe event to be human performance errors. 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. The inspectors discussed with the RPM any problems with the corrective actions planned or taken.
b. Findings
No findings were identified.
2RS2 Occupational As Low as Reasonably Achievable (ALARA) Planning and Controls
a. Inspection Scope
Verification of Dose Estimates and Exposure Tracking Systems The inspectors selected ALARA work packages and reviewed the assumptions and basis for the current annual collective exposure estimate for reasonable accuracy. The inspectors reviewed the applicable procedures to determine the methodology for estimating exposures from specific work activities and the intended dose outcome.
The inspectors verified that for the selected work activities that PSEG had established measures to track, trend, and, if necessary, to reduce, occupational doses for ongoing work activities. The inspectors verified that trigger points or criteria were established to prompt additional reviews and/or additional ALARA planning and controls. The inspectors reviewed PSEG's collective exposure performance during the Spring 2010 refueling outage at Unit 1 ('I RF20). Total collective exposure for this outage was the lowest ever at either Salem unit.
The inspectors evaluated PSEG's method of adjusting exposure estimates, or re planning work, when unexpected changes in scope or emergent work were encountered.
The inspectors determined that adjustments to exposure estimates were based on sound radiation protection and ALARA principles or that they were just adjusted to account for failures to control the work. The inspectors evaluated the frequency of these adjustments 10 determine the adequacy of the original ALARA planning process.
No findings were identified.
2RS4 Occupational Dose Assessment
a. Inspection Scope
§Qecial Bioassay The inspectors selected internal dose assessments obtained using in-vitro monitoring.
The inspectors reviewed and assessed the adequacy of PSEG's program for in-vitro monitoring of radionuclides, including collection and storage of samples.
The inspectors determined that PSEG had not specifically qualified their vendor laboratory to perform in-vitro sample counting, having neither audited the lab in the area of in-vitro analysis, nor verifying the lab's participation in an analYSis cross-check pmgram.
The inspectors reviewed the adequacy of PSEG's program for dose assessments based on airborne/DAC monitoring. The inspectors verified that flow rates and/or collection times for fixed head air samplers or lapel breathing zone air samplers were adequate to ensure that appropriate lower limits of detection are obtained. The inspectors reviewed the adequacy of procedural guidance used to assess dose when PSEG personnel apply protection factors. The inspectors reviewed dose assessments performed using airborne/DAC monitoring. The inspectors verified that PSEG's DAC calculations were representative of the actual airborne radionuclide mixture, including hard-to-detect nuclides.
The inspectors reviewed the adequacy of PSEG's internal dose assessments for any actual internal exposure greater than 10 millirem committed effective dose equivalent.
The inspectors determined that the affected personnel were properly monitored with calibrated equipment and the data was analyzed and internal exposures properly assessed in accordance with PSEG procedures.
Dosimeter Placement and Assessment of Effective Dose Equivalent for External
~posures The inspectors reviewed PSEG's methodology for monitoring external dose in situations in which non-uniform fields are expected or large dose gradients exist. The inspectors verified that PSEG had established criteria for determining when alternate monitoring techniques were to be implemented.
The inspectors reviewed dose assessments performed using multibadging during the current assessment period. The inspectors verified that the assessment was performed in accordance with PSEG procedures and dosimetric standards.
Shallow Dose Equivalent (SDE)
The inspectors review SDE dose assessments for adequacy. The inspectors evaluated PSEG's method for calculating SDE from distributed skin contamination or discrete radioactive particles.
Neutron Dose Assessment The inspectors evaluated PSEG's neutron dosimetry program, including dosimeter types and/or survey instrumentation.
The inspectors selected neutron exposure situations and verified that
- (a) dosimetry and/or instrumentation was appropriate for the expected neutron spectra,
- (b) there was sufficient sensitivity for low dose and/or dose rate measurement, and
- (c) neutron dosimetry was properly calibrated. The inspectors verified that interference by gamma radiation was accounted for in the calibration. The inspectors verified that time and motion evaluations were representative of actual neutron exposure events, as applicable.
For the special dosimetric situations reviewed in this section, the inspectors determined how PSEG aSSigned the dose of record for total effective dose equivalent, SDE. and lens dose equivalent.
b. Findings
No findings were identified.
OTHER ACTIVITIES
40A1 Performance Indicator (PI) Verification (71151 ~ 6 samples)a.
InsRection Scope The inspectors reviewed PSEG submittals for the Unit 1 and Unit 2 mitigating systems cornerstone PIs listed below. To verify the accuracy of the PI data reported during this period the data was compared to the PI definition and guidance contained in NEI 99-02, "Regulatory Assessment Performance Indicator Guideline," Revision 5.
Cornerstone: Mitigating Systems
- Unit 1 and Unit 2 AFW systems;
- Unit 1 and Unit 2 RHR systems; and
- Unit 1 and Unit 2 SW systems.
The inspectors verified the accuracy of the data' by comparing it to CAP records, control room operators' logs, the site operating history database, and key PI summary records.
b. Findings
No findings were identified.
40A2 Identification and Resolution of Problems (71152 -1 work-around sample)
.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 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 Review of Operator Workaround Program
a. Inspection Scope
The inspectors conducted a cumulative review of operator workarounds for Unit 1 and Unit 2 and assessed the effectiveness of PSEG's operator workaround program. The inspectors reviewed PSEG's control room distraction report, operator burden list, and operator burden self-assessment. The inspectors focused on the potential impact on mitigating systems and the potential to affect operator ability to implement abnormal and emergency operating procedures. The review included interviews with licensed opE~rators and walkdowns of main control room panels. Documents reviewed are listed in the Attachment.
b. Findings and Observations
No findings were identified.
PSEG identified twelve operator challenges at Unit 1 and Unit 2, but none of the challenges were classified as operator workarounds. The inspectors did not identify additional operator challenges or workarounds. The inspectors reviewed OP-AA-102 103, "OperatorWorkaround Program", and OP-AA-1 02-1 03 w1001 , UOperator Burdens Program>>, for PSEG program requirements and found that PSEG adequately implemented these procedures. The most recent operator burden assessment was reviewed for each unit. The inspectors determined that the cumulative impact of the identified operator challenges was within manageable limits.
40A3 Event Followwup (71153 - 3 samples)
.1 iQ!.osed) Licensee Event Report 05000272/2010-001-00, Automatic Start of the 1C EDG
On April 16, 2010, at 1641 hours0.019 days <br />0.456 hours <br />0.00271 weeks <br />6.244005e-4 months <br />, the 1C 4160 volt vital bus lost power. Surveillance testing was being performed to demonstrate the transfer of the 1C 4160 volt vital bus from one offsite power source to the second offsite power source. The 1C EDG automatically started but the EDG output breaker did not close per design. Abnormal operating procedure S1.0P-ABAKV-0003 was entered for loss of power to the 1C 4160 vollt vital bus. Fuel movement was in progress at the time of the event and was suspended.
Thl9 unexpected start of the 1C EDG was the result of the failure of the 13CSD breaker auxiliary position switch (52STA switch). The failure of the 52STA switch was the result of binding caused by mis-adjustment of the gap between the breaker and the 52STA switch assembly. The mis-adjustment was the result of unclear procedural guidance for measuring the breaker plunger gap. Corrective actions consist of replacement of the 13CSD 52STA switch, proper adjustment of the breaker plunger gap. inspection of other 41130 volt in-feed breaker plunger gaps, and procedure revisions to improve the guidance for measuring breaker plunger gaps. The inspectors' review of this issue noted a licensee identified violation of regulatory requirements, specifically that PSEG maintenance procedure guidance for measuring the breaker plunger gap was inadequate. The enforcement aspects ofthis violation are discussed in Section 40A7.
This LER is closed .
.2 (Closed) lER 05000272-2010-002-00. Automatic Reactor Trip Due to Main Power
Transformer Bushing Failure On July 7. 2010, at approximately 1118, an automatic reactor trip occurred due to a turbine trip above 50% reactor power. The turbine trip was caused by the actuation of the regular and back-up phase B...C differential relays in the main generator protection scheme, which was caused by arc flash across the B phase main power transformer bushing after an inadvertent actuation of the transformer fire protection deluge system.
The deluge system was actuated by one of the 18 air-pilot sprinkler heads that had mEllted due to the unusually high ambient temperatures combined with the transformer's heat, direct sunlight. and restricted ventilation caused by concrete walls that surround three sides of the main power transformer B phase. Mist from the deluge system actuation, driven by the transformer cooling fans, the heat rising from the transformer and the close proximity of the concrete wall enclosure, rose above the main power transformer B phase bushing and caused an arc flash and bushing failure. PSEG corrective actions included replacing the main power transformer deluge system air-pilot sprinkler heads with sprinkler heads that have a higher temperature setpoint. The inspectors completed a review of this LER and did not identify a violation of regulatory requirements. This lER is closed .
.3 (Closed) LER 05000272/2010-003-00, Failure to Comply with Technical Specification
3.0.4 On July 25, 2010, at 0940, a PSEG technician identified that the circuitry was disabled for the motor driven AFW pump automatic start on a trip of both steam generator feedwater pumps (SGFPs). At the time of discovery, Unit 1 was in Mode 1 and the AFW automatic start circuitry is required by TS 3.3.2.1 function 8f to be operable in Modes 1 and 2. PSEG re-established the automatic start of the AFW pumps on a trip of both SGFPs at 1557 on July 25, 2010.
The cause of the failure to re-establish the automatic start circUitry for the start of the motor driven AFW pumps on a trip of the SGFPs was due to operators performing the incorrect section of the procedure to re-establish the start circuitry during mode ascension. Corrective actions consisted of training, procedure revisions, and personnel accountability. The inspectors review of this issue noted a licensee identified violation of regulatory requirements, specifically that entry into Mode 2 with the circuitry required by TS 3.3.2.1 function 8f disabled was a condition prohibited by TS 3.0.4. The enforcement aspects of this violation are discussed in Section 40A7. This LER is closed.
40A5 Other Activities
.1 NRC Temporary Instruction (TO 2515/177 - Managing Gas Accumulation in Emergency
Core Cooling. Decay Heat Removal. and Containment Sgray Systems
a. Inspection Scope
ThE~ NRC staff developed TI 2515/177 to support the NRC's confirmatory review of licensee responses to NRC Generic letter (GL) 2008-01, "Managing Gas Accumulation in Emergency Core Cooling, Decay Heat Removal, and Containment Spray Systems."
Based on the review of PSEG's GL 2008-01 response letters, the Office of Nuclear Reactor Regulation (NRR) staff provided guidance on TI inspection scope to the regional inslPectors. The inspectors used this inspection guidance along with the TI to verify that PSEG implemented or was in the process of acceptably implementing the commitments, modifications, and programmatically controlled actions described in their GL 2008-01 response. The inspectors verified that the plant-specific information (including licensing basis documents and design information) was consistent with the information that PSEG submitted to the NRC in response to GL 2008-01.
The inspectors reviewed a sample of isometric drawings and piping and instrument
. diagrams and conducted selected system piping walkdowns to verify that PSEG's drawings reflected the subject system configurations and UFSAR descriptions.
Specifically, the inspectors verified the following related to a sample of isometric drawings for the CVCS, RHR, safety injection (SI), and containment spray (CS) systems:
- High pOint vents were identified;
- High points that did not have vents were recognized and evaluated with respect to their potential for gas accumulation;
- Other areas where gas could accumulate and potentially impact subject system operability, such as orifices in horizontal pipes, isolated branch lines, heat exchangers, improperly sloped piping, and under closed valves, were acceptably evaluated in engineering reviews or had ultrasonic testing (UT) points which would reasonably detect void formation; and
- For piping segments reviewed, branch lines and fittings were clearly shown.
The inspectors conducted walkdowns of portions of the above systems to reasonably assure the acceptability of PSEG's drawing utilized during their review of GL 2008-01.
The inspectors verified that PSEG conducted walkdowns of the applicable systems to confirm that the combination of system orientation, vents, instructions and procedures, tests, and training would ensure that each system was suffiCiently full of water to assure operability. The inspectors reviewed PSEG's methodology used to determine system piping high pOints, identification of negative sloped piping, and calculations of void sizes based on UT equipment readings to ensure the methods were reasonable.
The inspectors verified that PSEG included all emergency core COOling systems, along with supporting systems, within scope of the GL. In addition, the inspectors verified that P5EG acceptably addressed flashing of RHR suction lines when initiating RHR while the lines are at elevated temperatures to ensure system operability. The inspectors also reviewed engineering analyses associated with the development of acceptance criteria for <:is-found voids, which included engineering assumptions for void transport and acceptability of void fractions at the suction and discharge piping of the applicable system pumps. The inspectors coordinated this review with NRR, who was concurrently pursuing questions associated with void acceptance criteria at the time of the inspection.
The inspectors reviewed a sample of P5EG's procedures used for filling and venting the associated GL 2008~01 systems to verify that the procedures were effective in venting or redl:..Icing voiding to acceptable levels. The inspectors verified the installation of a hardware vent, located in the Unit 1 RHR cross connect discharge piping, as committed to in P5EG's GL response. A similar vent installation is planned for the upcoming Unit 2 outage in the spring of 2011. The inspectors also confirmed the planned implementation of an additional hardware high point vent modification on each unit that was associated with the common RHR cold Jeg branch point between the associated 51 to RHR check valves and was designed to allow any possible gas intrusion and accumUlation to be vented off (two vents per unit). The Unit 2 modification is planned for the Spring 2011 outage (design change request 80099810) and the Unit 1 modification is expected to be implemented in the Fall 2011 outage (design change request 80101453).
The inspectors verified that PSEG's surveillance frequencies were consistent with the UFSAR, T5s, and associated bases. The inspectors reviewed a sample of system venting surveillance results to ensure proper implementation of the surveillance program anc! that the existence of unacceptable gas accumulation was evaluated within the CAP, as necessary. In addition, on August 4, 2010, the inspectors observed portions of the performance of the Unit 2 monthly venting surveillance to assess the adequacy of procedures and implementation. The inspectors reviewed CAP documents to verify that selected actions described in P5EG's nine-month and supplemental submittals were acceptably documented, including completed actions and the implementation schedule for incomplete actions. The inspectors also verified that NRC commitments in PSEG's submittals were included in the CAP. Additionally, the inspectors reviewed evaluations and corrective actions for various issues PSEG identified during their GL 2008-01 review. The inspectors performed this review to ensure PSEG appropriately evaluated and adequately addressed any gas voiding concerns, including the evaluation of ope~rability for gas voids discovered in the field. Finally, the inspectors reviewed PSEG's training associated with gas accumulation to assess if appropriate training was provided to the operations and engineering support staff to ensure appropriate awareness of the effects of gas voiding. Documents reviewed are listed in the Attachment.
b. Findings
No findings were identified.
NRR is still evaluating some technical aspects associated with void acceptance criteria and will likely request additional information from PSEG. Because of this, the TI may require additional inspections prior to final closure. Final closure of GL 2008-01 for Units 1 and 2 will be documented via separate correspondence from NRR.
40A6 Meetings, Including Exit The inspectors presented the inspection results to Mr. C. Fricker and other members of PSEG management at the conclusion of the inspection on October 7, 2010. The inspectors asked PSEG whether any materials examined during the inspection were proprietary. No proprietary information was identified.
40A7 UcensesMldentified Violations The following violations of NRC requirements were identified by PSEG. They were determined to have very low safety significance (Green) and meet the criteria of Section 2.3 of the NRC Enforcement Policy, NUREG-1600, for being dispositioned as NCVs:
- TS 6.8.1 "Procedures and Programs" states, in part, that written procedures shall be established, implemented and maintained for activities specified in Regulatory Guide 1.33, Revision 2, February 1978, Regulatory Guide 1.33,Section IX. includes written procedures for performing maintenance, which can affect the performance of safety related equipment. Contrary to the above, PSEG did not adequately implement and maintain the 4KV Breaker Plunger Gap Verification maintenance procedure.
Specifically, the inappropriate guidance to perform plunger gap adjustments for 4KV magne-blast breakers resulted in a miswadjustment of the gap between the breaker closing plunger and 521STA auxiliary switch operating mechanism. This resulted in loss of power to the 1C vital bus for 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> on April 16, 2010.
This violation was determined to be of very low safety significance (Green) because it did not increase the likelihood of a loss of reactor coolant system (RCS) inventory, it did not affect PSEG's ability to terminate a leak path or add RCS inventory, and it did not degrade PSEG's ability to recover decay heat removal in the event it was lost. PSEG entered this violation in their CAP as notification 20459055.
- TS 3.2.1.1 function 8f requires that both motor-driven AFVV pumps start when both steam generator feed pumps trip when the reactor is in Modes 1 and 2. Contrary to this requirement. from 2132 hours0.0247 days <br />0.592 hours <br />0.00353 weeks <br />8.11226e-4 months <br /> on July 22.2010, to 1557 hours0.018 days <br />0.433 hours <br />0.00257 weeks <br />5.924385e-4 months <br /> on July 25,2010, lhis auto start function was disabled. Leads that were lifted to disable the auto start function during the forced outage were not properly re-Ianded prior to ascension to Mode 2.
This finding is of very low safety significance (Green) because the finding did not represent the loss of a system safety function, an actual loss of safety function of a single train for greater that the TS allowed outage time, or screen as potentially risk significant due to a seismic, flooding, or severe weather initiating event. PSEG entered this TS violation in their CAP as notification 20471722.
AITACHMENT:
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee personnel
- C. Fricker, Site Vice President
- E. Eilola, Plant Manager
- L. Rajkowski, Engineering Director
- R. DeSanctis, Maintenance Director
- J. Garecht, Operations Director
- J. Higgins, System Engineer
- F. Hummel, System Engineer
- R. Gary, Radiation Protection Manager
- S. Bowers, System Engineer
- E. Villar, Licensing Engineer
- M. Wolk, Senior Reactor Operator
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Closed
- 05000272/2010-001-00 LER Automatic Start of the 1C EDG (Section 40A3.1)
- 05000272/2010-002-00 LER Automatic Reactor Trip Due to Main Power Transformer Bushing Failure (Section 40A3.2)
- 0500027212010-003-00 LER Failure to Comply with Technical Specification 3.0.4 (Section 40A3.3)