IR 05000272/2010002

IR 05000272-10-002 and 05000311-10-002; on 01/01/10 - 03/31/10; Salem Nuclear Generating Station, Units 1 and 2; Event Follow-up, NRC Integrated Inspection Report

ML101320680
Person / Time
Site:	Salem
Issue date:	05/12/2010
From:	Arthur Burritt Reactor Projects Branch 3
To:	Joyce T Public Service Enterprise Group
BURRITT, AL
References
IR-10-002
Download: ML101320680 (24)

Text

UNITED STATES NUCLEAR REGULATORY COMMISSION

REGION I

415 ALLENDALE ROAD KING OF PRUSSIA, PENNSYLVANIA 19406-1415 May 12,2010 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 0500027212010002 and 0500031112010002

Dear Mr. Joyce:

On March 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 the inspection results discussed on April 1, 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.

The report documents one self-revealing finding of very low safety significance (Green). This finding was determined to involve a violation of NRC requirements" However, because of the very low safety significance and because it is entered into your corrective action program (CAP),

the NRC is treating this finding as a non-cited violation (NCV) consistent with Section VI.A.1 of the NRC Enforcement Policy. If you contest the NCV in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory Commission, A TIN: Document Control Desk, Washington, DC 20555 0001; with copies to the Regional Administrator, Region I; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at the Salem Nuclear Generating Station. In addition, if you disagree with the characterization of any finding in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region I, and the NRC Resident Inspector at Salem Nuclear Generating Station.

The information you provide will be considered in accordance with Inspection Manual Chapter (IMe) 0305. 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 accessibie from the NRC Web site at httD:/Iwww.nrc.gov/reading-rm/adams.html(the Public Electronic Reading Room).

Sincerely,

!~'1

/ /

l/

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 05000272/2010002 and 05000311/2010002 w/Attachment: Supplemental Information

REGION I==

Docket Nos: 50-272,50-311 License Nos: OPR-70, OPR-75 Report No: 05000272/2010002 and 05000311/2010002 Licensee: PSEG Nuclear LLC (PSEG)

Facility: Salem Nuclear Generating Station, Unit Nos. 1 and 2 Location: P.O. Box 236 Hancocks Briqge, NJ 08038 Dates: January 1, 2010 through March 31, 2010 Inspectors: D. Schroeder, Senior Resident Inspector H. Balian, Resident Inspector J. Furia, Senior Health Physicist Approved By: Arthur L Burritt, Chief Projects Branch 3 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

IR 0500027212010002,05000311/2010002; 01/01/2010 - 03/31/2010; Salem Nuclear

Generating Station Unit Nos. 1 and 2; Event Follow*up.

The report covered a three-month period of inspection by resident inspectors, and an announced inspection by a regional radiation specialist. One Green NCV was identified. The significance of most findings is indicated by their color (Green, White, Yellow, or Red) using lMC 0609, "Significance Determination Process" (SOP) and the cross-cutting aspect of a finding is determined using IMC 0305. "Operating Reactor Assessment Program." 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 TS 3.7.10, "Chilled Water System, Auxiliary Building Subsystem," was identified because the 12 chiller tripped on low chill water temperature during the starting of the 13 chiller for post-maintenance testing on December 7, 2010.

The inspectors determined that the cause of the chiller trip was inadequate troubleshooting that was conducted after the 12 chiller tripped on December 4, 2010.

Corrective actions included calibration of the low temperature trip instrument and raising the priority placed on correcting problems with the chillers. This issue was placed in PSEG's corrective action program.

The performance deficiency was more than minor because it is associated with the equipment performance attribute of the Mitigating Systems cornerstone, and it adversely affected the cornerstone objective to ensure the availability, reliability and capability of systems that respond to initiating events to prevent adverse consequences. Specifically, not conducting adequate troubleshooting in accordance MA-AA-716-004 affected the reliability of the emergency control air system by reducing the capability of the chilled water system to cool the emergency control air compressor. The finding was evaluated under IMe 0609, Attachment 4, Phase 1 screening, and was determined to require additional evaluation. The finding was subsequently evaluated in Phase 3 utilizing the Salem Standardized Plant Analysis Risk (SPAR) Model, Revision 3.51 with the Graphical Interface Module (GEM) 7. and confirmed to be of very low safety significance (Green). This performance deficiency has a cross-cutting aspect in the area of human performance because PSEG personnel did not use conservative assumptions in qecision making and adopt a requirement that the proposed action is safe in order to proceed. Specifically, when the complex troubleshooter was completed after the 12 chiller trip on December 4 and no cause for the chiller trip was identified, PSEG did not appropriately reconsider validating the low temperature trip set point in accordance with thE~ step originally included in the complex troubleshooter documentation. (Section 40A3.3) [H.1 (b)].

REPORT DETAILS

Summary of Plant Status

Salem Nuclear Generating Station Unit No.1 (Unit 1) began the period at full power. On January 3, operators lowered Unit 1 to 80 percent power when weather-related conditions caused a reduction in condenser cooling water flow. Operators returned Unit 1 to full power on January 5. On March 21, operators lowered Unit 1 to 90 percent power in response to a condensate system equipment problem. On March 27, operators returned Unit 1 to full power after repairs to the condensate system were completed. Unit 1 operated 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 January 3, operators tripped Unit 2 when weather-related conditions caused a reduction in condenser cooling water flow. Operators returned Unit 2 to full power on January 5. On January 21, Unit 2 automatically tripped following a main feedwater system malfunction.

Operators returned Unit 2 to full power on January 24. Unit 2 operated at or near full power for the remainder of the inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, and Emergency Preparedness

1R01 Adverse Weather Protection

.1 Evaluate Readiness for Impending Adverse Weather Conditions

a. Inspection Scope

The inspectors completed one impending adverse weather sample for the onset of high levels of river detritus. The inspector's reviewed PSEG's weather preparation activities related to potential river grass intrusion conditions. Inspectors assessed implementation of PSEG's grassing readiness plan through plant walk downs, corrective action program (CAP) review, and discussion with cognizant managers and engineers. Documents reviewed by inspectors are listed in the Attachment.

b. Findings

No findings of significance were identified.

1R04 Equipment Alignment

.1 Partial Walk dOWIl

a.

InSRection Scop@

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 auxiliary feedwater (AM) system on January 13 and 14 during and after maintenance to the 23 AFW pump

• Unit 1 and 2 rod control system on February 1 and 2 after manual alignment of the master cycler

• Unit 1 residual heat removal (RHR) on February 17 and 19 during and after maintenance affecting the 11 RHR train

• Unit 2,26 and 2C emergency diesel generators (EDG) and support systems following emergent inoperability of the 2A EDG on March 31

b. Findings

No findings of significance were identified.

1R05 Fire Protection (71111.050 - 4 samples;

==71111.05A - 1 sample)

.1 Fire Protection - Tours

a. Inspection Scope

==

The inspectors completed four quarterly fire protection inspection samples. The inspectors conducted tours of the areas listed below to assess the material condition and operational status of fire protection features. The inspectors verified that 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 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 1 auxiliary building, elevations 45' and 55'

• Salem common switch yard

• Unit 1 fuel handling building

• Unit 1 mechanical penetration area No findings of Significance were identified .

.2 Fire Protection - Drill Observation

a. Inspection Scope

The inspectors completed one fire drill observation inspection sample. The inspectors observed an unannounced fire drill conducted in the 28 EDG room. The inspectors observed the drill to evaluate the readiness of the plant fire brigade to fight fires. The inspectors verified that PSEG staff identified deficiencies; openly discussed them in a self-critical manner at the drill debrief; and took appropriate corrective actions. Specific attributes evaluated were: proper wearing ofturnout gear and self-contained breathing apparatus; proper use and layout of fire hoses; employment of appropriate fire fighting techniques; sufficient fire fighting equipment brought to the scene; effectiveness of fire brigade leader communications, command, and control; search for victims and propagation of the fire into other plant areas; smoke removal operations; utilization of pre-planned strategies; and adherence to the pre-planned drill scenario and drill objectives.

b. Findings

No findings of Significance were identified.

1R06 ,Flood Protection Measures

.1 Internal Flooding

a. Inspection Scope

The inspectors completed one internal flooding area inspection sample. The inspectors evaluated flood protection measures for the Unit 1 and Unit 2 safety injection pump rooms. The inspectors walked down the areas to assess the operational readiness to protect redundant safety-related components and vital electric power systems from internal flooding. These features included plant drains, flood barrier curbs, and motor spray shields. The inspectors also reviewed the results of flooding evaluations, preventive maintenance history, and corrective action notifications associated with flood protection measures. Documents reviewed are listed in the Attachment.

b. Findings

No findings of significance were identified.

1R11 Licensed Operator Requalification Program (71111.110 - 1 sample)

.1 '

Regualification Activities Review by Resident Staff

a. Inspection Scope

The inspectors completed one quarterly licensed operator requalification program sample. Specifically, the inspectors observed an unannounced simulator scenario on January 19. The scenario included clogging of a service water (SW) strainer, followed by a SW leak into the SW intake structure leading to a loss of all three SW pumps in the affected bay. This was followed by a steam generator feed pump trip and rapid load reduction. During the load reduction, turbine vibrations necessitated a plant trip. The trip was complicated by a loss of one vital electrical power bus and a totall05s of AFW.

that required the crew to recover the secondary heat sink by feeding steam generators with main condensate pumps.

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. Findings

No findings of significance 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 one component and reviewed PSEG's periodic evaluation of maintenance effectiveness at Salem that was conducted in accordance with 10 CFR 50.65 (a)(3).

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 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 (WOs), corrective action notifications, and preventive maintenance tasks. The documents reviewed are listed in the Attachment. The inspectors evaluated the structures, systems, and components (S5Cs) listed below:

• Unit 1 and 2 containment fan coil unit SW outlet valves (SW72); and

• Salem periodic evaluation on maintenance effectiveness.

No findings of significance were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

The inspectors completed four 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 walk downs. 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, 11 component cooling heat exchanger (CCHX) unavailability during planned maintenance on January 20

• Unit 1, concurrent unavailability of the 12 component cooling water pump and the station gas turbine generator for planned maintenance on March 17

• Unit 1 & 2, concurrent unavailability of the Unit 2 control room emergency air conditioning system and the station gas turbine generator for planned maintenance on March 18

• Unit 2, emergent unavailability of the 2A EDG on March 31

b. Findings

No findings of significance were identified.

1R15 Operability Evaluations

a.

Inspection ScoQe The inspectors completed five operability evaluation inspection samples. The inspectors reviewed the operability determinations for degraded or non-conforming conditions associated with:

• Unit 1 and Unit 2 engineered safeguards feature to automatically start motor driven AFW pumps after both main feedwater pumps have tripped;

• Unit 2 intermediate range nuclear instrument following 21 steam generator feedwater pump (SGFP) trip;

• Unit 2, 21 safety injection pump given an oil leak from the pump outboard bearing;

• Unit 1 rod position indication given malfunction of a rod step counter; and

• Unit 1, operability of the chemical volume control system (CVeS) given elevated packing leakage from the 13 cves pump.

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. Findings

No findings of significance were identified.

1R19 Post-Maintenance Testing

a. Inspection 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 was calibrated, 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 60087342, planned corrective maintenance on 2MS52, AFW pump turbine trip valve;

• WO 30114399, planned preventive maintenance on 14SW72 14 CFCU SWoutlet isolation valve;

• WO 30143571. planned maintenance on 22 auxiliary building ventilation exhaust fan;

• . WO 30101989. planned maintenance on 11SW153. RHR pump room cooler SW control valve pneumatic actuator;

• WO 30184621, emergent corrective maintenance on 22SW24. 22 SW strainer blow down valve pneumatic actuator;

• WO 30131853. planned maintenance and modification to 11CC16. 11 RHR HX outlet MOV; and

• WO 60089388. emergent maintenance on the 22 SW strainer.

b. Findings

No findings of significance were identified.

1R20 Refueling and Other Outage Activities

.1 Plant Trip Following 21 SGFP Trip

a. Inspection Scope

On January 21, Unit 2 tripped following a trip of the 21 SGFP that led to low steam generator water levels. The 22 SGFP also tripped shortly after the plant tripped due to an initially unknown cause. Due to this complication, prior to plant start-up, the inspectors conducted risk-informed walk downs of essential Unit 2 SSCs to independently assess their readiness for plant restart and PSEG's configuration control.

The inspectors walked down accessible portions of the following Unit 2 systems/areas:

EDGs, vital4KV switchgear and 480V motor control centers. component cooling water.

safety injection. fuel oil transfer and storage. AFW. and control room instrumentation panels. The inspectors observed startup activities, including initlallalching and startup of the 22 SGFP. rod control startup. main turbine latching. and initial roll of the main turbine.

b. Findings

No findings of significance 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 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 the American Society of Mechanical Engineers Code,Section XI for pump and valve testing. Documents reviewed are listed in the

.

• S1.0P-ST.DG-0013, 18 Diesel Generator Endurance Run

• S2,OP-ST.RC-0008, Unit 2 Reactor Coolant System (ReS) Water Inventory Balance

• S2.IC-SC.RCP-0018, 2PT-456 Pressurizer Pressure Protection Channel II

• S2.0P-ST.SJ-0001, Inservice Testing (1ST) of 21 Safety Injection Pump

• S1,OP-ST.SW-0001, 1ST of 11 SW Pump

b. Findings

No findings of significance were identified.

1EP6 Drill Evaluation

.1 Simulator Scenario Observation on January 19

a. Inspection Scope

The inspectors completed one drill evaluation inspection sample. On January 19, the inspectors observed a drill from the control room simulator during an evaluated licensed operator requalificatlon training scenario. The inspectors evaluated operator pE!rformance related to developing event classifications and notifications, The inspectors reviewed the Salem Event Classification Guides. The inspectors referenced Nuclear Energy Institute (NEI) 99-02, "Regulatory Assessment Performance Indicator (PI)

Guideline," Revision 5, and verified that PSEG correctly counted the evaluated scenario's contribution to the NRC PI for drill and exercise performance.

b. Findings

No findings of significance were identified .

.2 Training Drill Observation on February 23

a.

Inspection Scop~

The inspectors completed one drill evaluation inspection sample. On February 23,2010, the inspectors observed a training drill from the control room simulator, the technical support center, and the operations support center. The inspectors attended the drill debrief to ensure that PSEG captured drill deficiencies in their critique. The inspectors evaluated the drill performance related to developing event classifications and notifications. The inspectors reviewed the Salem Event ClaSSification Guides and Emergency Plans. The inspectors referenced NEI 99-02, "Regulatory Assessment PI Guideline," Revision 5, and verified that PSEG correctly counted the drill's contribution to the NRC PI for drill and exercise performance.

b. Findings

No findings of significance were identified .

.3 Practice Exercise Observation on March 24

a. Inspection Scope

The inspectors completed one drill evaluation inspection sample. On March 24, 2010, the inspectors observed a training drill from the technical support center. The inspectors evaluated licensee performance relative to developing event classifications and notifications. The inspectors reviewed the Salem Event Classification Guides and Emergency Plans. The inspectors referenced NEI 99-02, "Regulatory Assessment PI Guideline," Revision 5, and verified that PSEG correctly counted the drill's contribution to the NRC PI for drill and exercise performance.

b. Findings

No "findings of significance were identified.

2RS5 Radiation Monitoring Instrumentation

a. Inspection Scope

PSEG's program was evaluated against the requirements contained in the Salem Station Off-Site Dose Calculation Manual (ODCM) for the calibration and maintenance of radiation monitOring equipment utilized in measuring plant effluents.

Walkdowns and Observations The inspectors walked down effluent radiation monitOring systems, including liquid and gaseous system. The inspectors verified that effluent/process monitor configurations aligned with ODCM descriptions.

Calibration and Testing Program.

Process and Effluent Monitors The inspectors verified that channel calibration and fUnctional tests were performed consistent with radiological effluent technical specifications (RETS)/ODCM. The inspectors verified that

(a) PSEG calibrated its monitors with National Institute of Standards and Technology (NIST) traceable sources,

(b) if a primary calibration, it adequately represented the plant nuclide mix,

(c) if a secondary calibration, it verified the primary calibration, and

(d) the channel calibrations encompassed the instrument's alarm setpoints.

The inspectors verified that effluent monitor alarm setpoints were established as provided in the ODCM and station procedures. For changes to effluent monitor setpoints, the inspector evaluated the basis for changes to ensure that an adequate justification existed.

b. Findings

No findings of significance were identified.

2RS6 Radioactive Gaseous and Liquid Effluent Treatment

a. Inspection Scope

PSEG's program was evaluated against the requirement to provide adequate protection of the public from effluent releases resulting from normal operations of the plant by maintaining the dose to the maximally exposed member of the public as far below the dose limits in 10 CFR Part 20 and 40 CFR Part 190, as low as is reasonably achievable (ALARA). Criterion 60 in 10 CFR Part 50 Appendix A, requires the control and appropriate mitigation of radioactive materials released as plant effluents. In addition, Paragraph 50.34a (and the associated Appendix I) to 10 CFR Part 50 provide dose based design criteria to ensure the effectiveness of plant effluent processing systems in maintaining effluent releases to the plant environs ALARA.

Event Report and Effluent Report Reviews The inspectors reviewed the radiological effluent release reports issued since the last inspection. The inspectors verified that the reports were submitted as required by the ODCMITSs. The inspectors identified radioactive effluent monitor operability issues reported by PSEG as provided in effluent release reports, and verified that the issues were entered into the CAP and adequately resolved.

ODCM and Final Safety Analysis Report (FSAR) Reviews The inspectors reviewed changes to the ODCM made by PSEG since the last inspection verses the guidance in NUREG~1301, 1302 and 0133 and Regulatory Guides (RGs) 1.109, 1.21 and 4.1. The inspectors verified that PSEG did not identify any contaminated non-radioactive systems that were disclosed either through an event report or were documented in the ODCM since the last inspection.

Groundwater Protection Initiative (GPO Program The inspectors reviewed reported groundwater monitoring results, and changes PSEG's written program for identifying and controlHng contaminated spillslleaks to groundwater.

Procedures. Special Reports & Other Documents The inspectors reviewed licensee event reports (LERs), event reports and/or special reports related to the effluent program issued since the previous inspection. The inspectors identified no additional focus areas for the inspection based on the scope/breadth of problems described in these reports. The inspectors also reviewed effluent program implementing procedures, particularly those associated with effluent sampling, effluent monitor set point determinations and dose calculations.

Walk downs and Observations The inspectors walked down selected components of the gaseous and liquid discharge systems to verify that equipment configuration and flow paths were in accordance with procedures, and to review and assess equipment material condition. For equipment or areas associated with the systems selected that were not readily accessible due to radiological conditions, the inspectors reviewed PSEG's material condition surveillance records. The inspectors walked down those filtered ventilation systems whose test results were reviewed during the inspection. The inspectors verified that there were no conditions, such as degraded high-efficiency particulate air (HEPA)/charcoal banks, improper alignment, or system installation issues that would impact the performance, or the effluent monitoring capability of the effluent system. The inspectors verified that PSEG did not make significant changes to their effluent release points.

The inspectors observed the routine processing and discharge of effluents (including sample collection and analysis). The inspectors verified that appropriate effluent treatment equipment was used and that radioactive liquid waste was processed and discharged in accordance with procedure requirements and discharge permits.

Sampling and Analyses The inspectors reviewed selected effluent sampling activities and verified that adequate controls were implemented to ensure representative samples were obtained (e.g, provisions for sample line flushing, vessel recirculation, composite samplers, etc.). The inspectors verified that the facility did not routinely rely on the use of compensatory sampling in lieu of adequate system maintenance, based on the frequency of compensatory sampling since the last inspection.

The inspectors reviewed the results of the inter-laboratory comparison program to verify the quality of the radioactive effluent sample analyses. The inspectors verified that the inter-laboratory comparison program include hard-to-detect isotopes as appropriate.

Instrumentation and Equipment Effluent Flow Measuring Instruments The inspectors reviewed PSEG's methodology for determining effluent stack and vent flow rates. The inspectors verified that the flow rates were consistent with RETS/ODCM and FSAR values, and that differences between assumed and actual stack and vent flow rates did not affect the results of the projected public doses.

Air Cleaning Systems The inspectors reviewed the surveillance test results for testing completed since the previous inspection for TS required ventilation effluent discharge systems (HEPA and charcoal filtration meet TS acceptance criteria).

Dose Calculations The inspectors reviewed radioactive liquid and three gaseous waste discharge permits.

The inspectors verified that the projected doses to members of the public were accurate and based on representative samples of the discharge path. The inspectors evaluated the methods used to determine the isotopes that were included in the source term to ensure all applicable radionuclides were included, within detectability standards. The inspectors also reviewed the current Part 61 analyses to ensure hard-to-detect radionuclides were included in the source term.

The inspectors reviewed changes in PSEG's offsite dose calculations since the last inspection. The inspector verified that the changes were consistent with the ODCM and RG 1.109. The inspectors reviewed meteorological dispersion and deposition factors used in the ODCM and effluent dose calculations to ensure appropriate factors were being used for public dose calculations. The inspectors reviewed the latest Land Use Census and verified that changes were factored into the dose calculations.

GPI Implementation The inspector verified that PSEG was continuing to implement the voluntary NEI/lndustry GPI since the last inspection. The inspectors reviewed monitoring results of the GPI to determine if PSEG had implemented its program as intended, and to identify any anomalous results.

The inspectors reviewed identified leakage or spill events and entries made into 10 CFR 50.75

(g) records. The inspectors reviewed evaluations of leaks or spills, and reviewed any remediation actions taken for effectiveness. The inspectors reviewed onsite contamination events involving contamination of groundwater.

The inspectors verified that on-site ground water sample results and a description of any significant on-site leaks/spills into ground water for each calendar year were documented in the Annual Radiological Environmental Operating Report for Radiological Environmental Monitoring Program or the Annual Radiological Effluent Release Report for the RETS.

.

Problem Identification and Resolution (PI&R)

The inspectors verified that problems associated with the effluent monitoring and control program were being identified by PSEG at an appropriate threshold and were properly addressed for resolution in the CAP.

b. Findings

No findings of significance were identified.

OTHER ACTIVITIES

40A1 Performance Indicator (PI) Verification (71151 - 6 samples)

a. Inspection Scope

The inspectors reviewed PSEG submittals for the Unit 1 and Unit 2 Mitigating Systems cornerstone Pis and the Unit 1 and Unit 2 Barrier Integrity cornerstone Pis discussed below. Data reviewed was for alf four quarters of calendar year 2009. 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 Indicator Guideline," Revision 5.

Cornerstone: Mitigating Systems

• Unit 1 and 2 Safety System Functional Failures

Cornerstone: Barrier Integriti

• Unit 1 and 2 Reactor Coolant System (RCS) Unidentified Leak Rate; and

• Unit 1 and 2 RCS Specific Activity.

The inspectors reviewed main control room logs and were familiar with leak rate data through plant status reviews required by NRC IMC 2515, Appendix D, "Plant Status."

b. Findings

No findings of significance were identified.

40A2 Identification and Resolution of Problems

.1 Review of Items Entered into the CAP

a. Inspection Scope

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.

b. Inspection Scope

No findings of significance were identified.

40A3 Event Follow-UR (71153 - 3 samples)

.1 Plant Trip in Response to Loss of Circulating Water

a. .

Inspection ScoRe On January 3, operators manually tripped Unit 2 in response to a loss of circulating water caused by freezing conditions in the Delaware Bay. The inspectors responded to the plant to observe control room activities following the trip and to assess plant conditions. The inspectors completed walk downs of the SW intake structure and circulating water intake structure to assess severity of conditions and any potential impact on the ultimate heat sink.

b.

Bndings No findings of Significance were identified .

.2 Plant Trip following 21 Steam Generator Feed Pump Trip

a. Inspection Scope

On January 21, Unit 2 automatically tripped following a trip of the 21 SGFP that led to low steam generator water *Ievels. The 22 SGFP tripped shortly after the plant trip. 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 and post-trip conditions for potential impacts on safety related equipment and reviewed PSEG's post-trip report prior to restart.

Following plant stabilization in Mode 3, the inspectors conducted risk-informed walk downs of essential Unit 2 SSCs that were potentially impacted by the plant transient to independently assess their condition and functionality and to ensure that PSEG adequately identified conditions adverse to quality during their post-event walk downs.

The inspectors walked down accessible portions of the following Unit 2 systems: main steam (including main steam isolation valves), feed and condensate (including the steam generator feed pumps and controls). AFW, atmospheric relief valves and steam dumps, reactor trip breakers, and control room instrumentation panels.

b. Inspection Scope

No findings of significance were identified .

.3 (Closed) LER 05000272J2009~001-01, Chillers Inoperability Exceeds TS Allowed Outage

Time

a. Inspection Scope

On December 7,2009, during post maintenance operability testing for the 13 chiller, the 12 chiller tripped on low temperature freeze protection. Because two chillers were inoperable operators entered a 72-hour TS LCO shutdown action statement. Detailed troubleshooting for the 12 chiller trip determined that the low temperature trip switch for the 12 chiller was set 7 OF above its required setpoint. The cause analysis determined that this incorrect switch setting existed between December 2,2009, and December 7, 2009. As a result, PSEG determined that the two chillers, 12 and 13, were inoperable for longer than the 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> allowed by TS 3.7:10, action b.3. The inspectors completed a review of this LER and identified one finding of very low safety Significance as documented below. This LER is closed.

b. Findings

Introduction:

A self-revealing Green non-cited violation of Technical SpeCification (TS)3.7.10, Chilled Water System, Auxiliary Building Subsystem, was identified because the 12 chiller tripped on low chill water temperature during the starting of the 13 chiller for post-maintenance testing on December 7,2010. The inspectors determined that the cause of the chiller trip was inadequate troubleshooting that was conducted after the 12 chiller tripped on December 4, 2010. Specifically, technicians did not verify the setpoint for the 12 chiller low temperature trip in accordance with the troubleshooting steps defined by the original complex troubleshooter.

Description:

The chilled water system provides space cooling to several plant areas and equipment cooling to the safety-related emergency control air compressor. Each unit has three chillers that are required to be operable during normal power operations.

On November 30,2009, the 12 chiller was removed from service for maintenance and design change installation. With one chiller inoperable, operators entered a 14-day shutdown action statement for TS 3.7.10. On December 2, 2009, operators declared the 13 chiller inoperable due to an emergent failure. At that time, because the 12 chiller was still out of service for maintenance, the emergent failure required operators to enter a 72-hour shutdown action statement for TS 3.7.10. Approximately 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> later on December 4, PSEG completed maintenance on the 12 chiller; but it subsequently tripped on freeze protection during the post maintenance test. PSEG completed troubleshooting using the guidance provided in PSEG procedure MA-AA-716-004, Conduct of Troubleshooting, but did not identify a cause for the low temperature trips.

After completion of troubleshooting on December 4, PSEG completed S1.0P-ST.CH 0004, Chilled Water System, chillers, to confirm 12 chiller operability. This testing ran the 12 chiller under a steady state load for seven hours. After successful completion of the testing, operators declared the 12 chiller operable and exited the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> LCO shutdown action statement. At that time the plant remained in the original 14-day LCO shutdown action statement because the 13 Chiller was still out of service for maintenance.

On December 7, 2009, after completion of 13 chiller maintenance, PSEG began operability testing for the 13 chiller. During this retest, the load on the 12 chiller changed as a result of starting the 13 chiller, and tile 12 chiller again tripped on low temperature I

freeze protection. This time PSEG completed troubleshooting that included verification I

of the low temperature switch set point and, in fact, this troubleshooting determined that the low temperature trip switch was set 7 degrees F above its required setting.

i I

PSEG determined that the low temperature freeze protection set point knob was probably turned during the design change installation on November 30,2009. This I maintenance involved pulling wires in the cabinet that housed the low temperature I cutout switch adjustment knob. Because this switch setting existed between December 2 through December 7, while the 13 chiller was inoperable for maintenance, both the 12 and 13 chillers were inoperable for longer than the 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> allowed by TS 3.7.10 action I

b.3.

.

PSEG performed an apparent cause evaluation for this TS violation. PSEG determined that one of the causal factors for the TS violation was inadequate troubleshooting after the 12 chiller tripped on low temperature on December 4, 2009. As stated above, immediately after the trip, PSEG personnel approved a complex trouble shooting procedure that included an action to validate the set point of the low temperature trip set point. but PSEG did not perform that step because the switch was recently calibrated, it was not worked on during the recent maintenance and design change Installation, and its set point did not typically drift This decision appeared reasonable when it was originally approved. However, the inspectors determined that, after the complex troubleshooter was implemented and no cause for the chiller trip was identified, PSEG deviated from the guidance in its troubleshooting procedure because it did not appropriately reconsider validating the low temperature trip set point in accordance with the original troubleshooter before it declared the 12 chiller operable. As a result PSEG did not identify and correct the cause of the December 4, 2009, 12 chiller trip and did not restore the chiller to fully operable status, until the 12 chiller tripped again on December 7,2009.

Analysis:

The inspectors determined that, in accordance with MA~AA-716~004, Conduct of Troubleshooting, PSEG did not complete adequate troubleshooting following the December 4, 2009. trip of the 12 chiller. This resulted in operators returning the 12 chiller to operable status before it was fully operable, and operating the plant with both the 12 and 13 chillers inoperable for greater than the TS allowed outage time. This was a performance deficiency.

The inspectors determined that the performance deficiency was more than minor because it was associated with the equipment performance attribute of the Mitigating Systems cornerstone, and it adversely affected the cornerstone objective to ensure the

. availably, reliability and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, not conducting adequate troubleshooting in accordance MA-M-716-004 affected the reliability of the emergency control air system by reducing the capability of the chilled water system to cool the emergency control air compressor. The finding was evaluated under MC 0609, Attachment 4, Phase 1 screening, and was determined to require additional evaluation. Specifically, the finding represented an actual loss of safety function of a single Train, for greater than its TS allowed outage time. The finding was evaluated in Phase 2 using Salem SDP Notebook and pre-solved tables and confirmed in Phase 3 utilizing the Salem Standardized Plant Analysis Risk (SPAR) Model, Rev 3.51 with the Graphica! Interface Module (GEM) 7.

Although one chiller was out of service for maintenance, and nominal test and maintenance is included in the model, the Phase 3 evaluation utilized a bounding assumption that both chillers had failed. With these bounding conditions, the finding was confirmed to be of very low safety significance (Green). The dominant accident sequences involved a loss of control air (LCA) coupled with failures of the station blackout compressor, failure to maintain steam generator level, and failure of auxiliary feedwater. Contributions from a large early release (LERF) and external events did not need to be considered due to low risk associated with this issue.

This performance deficiency has a cross-cutting aspect in the area of human performance because PSEG personnel did not use conservative assumptions in decision making and adopt a requirement that the proposed action is safe in order to proceed. Specifically, when the complex troubleshooter was completed after the 12 c~liUer trip on December 4 and no cause for the chiller trip was identified, PSEG did not appropriately reconsider validating the low temperature trip setpoint in accordance with the step originally included in the complex troubleshooter documentation. H.1(b)

Enforcement:

TS 3.7.10, Chilled Water System. Auxiliary Building Subsystem, requires in part, that with two chillers inoperable, that at least one chiller be restored to operable status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, or be in at least hot standby within the next six hours and in cold shutdown within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />. Contrary to these requirements, PSEG's past operability evaluation demonstrated that the 12 chiller was inoperable during the period from December 2,2009 through December 7,2009, while the 13 chiller was also inoperable, which exceed the allowable outage time for having two chillers inoperable.

The failure to comply with applicable limiting condition of operation completion times is a violation of PSEG's TS. However, because of the low safety significance and because it was ent~red into PSEG's corrective action program as Notification 20446414, the NRC is treating this issue as an NCV in accordance with Section VI.A.1 of the NRC's Enforcement Policy NCV 05000272/2010002*01, Chillers Inoperability Exceeds TS Allowed Outage Time 40A5 Other Activities

.1 Steam Generator Replacement Inspection

a. Inspection Scope

On February 23-24,2010, the inspectors observed the preparation and shipment of the first two used steam generators from Salem Unit 2.

In April 2008, Salem Unit 2 replaced all four of its steam generators, with the used steam generators placed in an outside storage location adjacent to the low-level radioactive waste storage building. The used generators were designated for burial at the Barnwell Low-Level Waste Disposal Facility.

The inspectors observed and reviewed:

• Securing of the two steam generators (SG-22 and SG-24) on a barge for transport to the Barnwell;

• Marking of the steam generators in accordance with Department of Transportation (DOT) SP-14455 (DOT Special Permit SP-14455 allows for the transport of the steam generators as a special shipment of a surface contaminated object (SCO-II);

• Uniform Waste Manifests (NRC Form 540 and NRC Form 541) for the steam generators to be shipped;

• Radiological postings and controls for the transportation activities; and

• Training of all personnel associated with the transport activity.

The inspectors also observed the movement of a steam generator (SG-21) from temporary laydown area #1 (adjacent to the low-level radioactive waste storage building)to temporary laydown area #2, adjacent to the barge dock.

The inspectors evaluated licensee activities against the requirements contained in 10 CFR 71.5, 10 CFR 20 and DOT SP-14455.

b. Findings

No findings of significance were identified.

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 April 1, 2010. The inspectors asked PSEG whether any materials examined during the inspection were proprietary.

No proprietary information was identified.

ATIACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee personnel

C. Fricker Site Vice President

S. Bowers System Engineer

D. Boyle Program Engineer

E. Eilola Plant Manager

A. Garcia System Engineer

F. Hummel System Engineer

J. Morrison Maintenance Supervisor

C. Pupek Risk Engineer

M. Rahmani System Engineer

J. Stead System Engineer

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

None

Opened/Closed

05000272/2010002-01 NCV Chillers InoperabiJity Exceeds TS Allowed Outage Time (Section 40A3.3)

Closed

05000272/2009~001-01 LER Chillers Inoperability Exceeds TS Allowed Outage Time (Section 40A3.3)

Discussed

None