IR 05000272/2008003

IR 05000272-08-003, 05000311-08-003, on 04/01/2008 - 06/30/2008, Salem Nuclear Generating Station Units 1 and 2, Maintenance Risk Assessment and Emergent Work Control, Operability Evaluations, Surveillance Testing

ML082200302
Person / Time
Site:	Salem
Issue date:	08/05/2008
From:	Arthur Burritt Reactor Projects Branch 3
To:	Levis W Public Service Enterprise Group
burritt al
References
IR-08-003
Download: ML082200302 (67)

Text

UNITED STATES NUCLEAR REGULATORY COMMISSION ust 5, 2008

SUBJECT:

SALEM NUCLEAR GENERATING STATION, UNIT NOS. 1 AND 2 -

NRC INTEGRATED INSPECTION REPORT 05000272/2008003 and 05000311/2008003

Dear Mr. Levis:

On June 30, 2008, 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 July 9, 2008, with Mr. Braun and other members of your staff.

The inspection examined activities conducted under your license as they relate to safety and compliance with the Commissions rules and regulations and with the conditions of your license.

The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.

The report documents three self-revealing findings of very low safety significance (Green).

These findings were all determined to involve violations of NRC requirements. However, because of their very low safety significance and because they were entered into your corrective action program, the NRC is treating this finding as a non-cited violation (NCV) consistent with Section VI.A.1 of the NRC Enforcement Policy. If you contest any NCV in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001; with copies to the Regional Administrator, Region I; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at the Salem Generating Station.

In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRC's document system (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

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 05000272/2008003 and 05000311/2008003 w/Attachment: Supplemental Information cc w/encl:

T. Joyce, Senior Vice President, Operations R. Braun, Site Vice President K. Chambliss, Director, Nuclear Oversight J. Spears, Acting Director of Finance G. Gellrich, Salem Plant Manager J. Keenan, General Solicitor, PSEG M. Wetterhahn, Esquire, Winston and Strawn, LLP L. Peterson, Chief of Police and Emergency Management Coordinator P. Baldauf, Assistant Director, NJ Radiation Protection Programs P. Mulligan, Chief, NJ Bureau of Nuclear Engineering, DEP H. Otto, Ph.D., Administrator, DE Interagency Programs, DNREC Div of Water Resources Consumer Advocate, Office of Consumer Advocate, Commonwealth of Pennsylvania N. Cohen, Coordinator - Unplug Salem Campaign E. Zobian, Coordinator - Jersey Shore Anti Nuclear Alliance

SUMMARY OF FINDINGS

IR 05000272/2008003, 05000311/2008003; 04/01/2008 - 06/30/2008; Salem Nuclear

Generating Station Unit Nos. 1 and 2; Maintenance Risk Assessment and Emergent Work Control, Operability Evaluations, Surveillance Testing.

The report covered a three-month period of inspection by resident inspectors, and an announced inspection by a regional radiation specialist, a regional reactor safety inspector, a regional security inspector, and a regional projects inspector. Three Green non-cited violations (NCVs), and one unresolved item were identified. The significance of most findings is indicated by their color (Green, White, Yellow, or Red) using Inspection Manual Chapter (IMC) 0609,

"Significance Determination Process" (SDP). Findings for which the SDP does not apply may be Green or be assigned a severity level after NRC management review. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, "Reactor Oversight Process," Revision 4, dated December 2006.

Cornerstone: Initiating Events

Green.

A self-revealing non-cited violation of Technical Specification (TS)6.8.1.a, Procedures and Programs, was identified because PSEG did not maintain adequate control of the system configuration for the Unit 2 chill water system during maintenance on the 21 chiller. Specifically, on May 27, 2008, all three Unit 2 chill water system chillers tripped due to an error in the safety tagging sequence specified by the work control documents for maintenance on the 21 chiller.

This finding is more than minor because it is associated with the configuration control attribute of the Initiating Events cornerstone, and it adversely affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, unavailability of all three chillers increased the likelihood of a loss of control air that could result in a complicated plant trip. Per Inspection Manual Chapter (IMC) 0609, Attachment 0609.04, initial screening and characterization of findings, the inspectors conducted a Phase 1 analysis and determined that this finding required a Phase 2 analysis because the finding contributed to both the likelihood of a reactor trip and the likelihood that mitigation equipment or functions will not be available. The inspector determined that the finding was of very low safety significance (Green) using the Salem plant specific Phase 2 pre-solved worksheets in accordance with IMC 0609, Appendix A,

Determining the Significance of Reactor Inspection Findings for At-Power Situations.

This finding has a cross-cutting aspect in the area of human performance because PSEG personnel did not follow procedures H.4(b). Specifically, revisions to the work control document for tagging the 21 chiller did not comply with the requirements of PSEG procedure SH.OP-AP.ZZ-0051, Safety Tagging Operations. (Section 1R13)

Cornerstone: Mitigating Systems

Green.

A self-revealing non-cited violation of Technical Specification (TS)6.8.1.a, Procedures and Programs, was identified because PSEG did not adequately maintain the calibration of the Unit 2 reactor vessel level indication system (RVLIS). Specifically, scaling for both RVLIS dynamic range channels was not completed when required. This resulted in Unit 2 RVLIS being inoperable for 13-days.

The finding is more than minor because it is associated with the equipment performance attribute of the Mitigating Systems cornerstone and because it affected the cornerstone objective of ensuring the reliability of systems that respond to initiating events to prevent undesirable consequences. Specifically, operators were not aware that both channels of RVLIS were inoperable and could have taken non-conservative actions during an inadequate core cooling or loss of coolant inventory event. Per inspection manual chapter (IMC) 0609.04,

Initial Screening and Characterization of Findings, the inspectors conducted a Phase 1 screen and determined the finding to be of very low safety significance (Green).

This finding has a cross-cutting aspect in the area of human performance because PSEG did not appropriately coordinate work activities as necessary to keep personnel apprised of work status and the operational impact of work activities H.3(b). Specifically, PSEG did not ensure RVLIS scaling was completed per the established work control process because engineering did not adequately communicate the importance of entering the new dynamic range coefficients to the operability of the RVLIS system. (Section 1R15)

Cornerstone: Barrier Integrity

Green.

A self-revealing non-cited violation of TS 6.8.1.a, Procedures and Programs was identified because the 22 Containment Fan Coil Unit (CFCU) had cooling water flow to the motor cooler inadvertently isolated during a routine surveillance test. Specifically, the surveillance procedure did not include steps to operate specific gage isolation valves to place a test gage in service, and as a result technicians repositioned the wrong valves.

This finding is more than minor because it is associated with the system, structure, and component (SSC) and barrier performance attribute of the Barrier Integrity cornerstone and it affects the cornerstone objective of providing reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. Specifically, unavailability of the 22 CFCU represented an actual loss of defense in depth of a system that controls containment pressure. Per inspection manual chapter (IMC) 0609,

Attachment 0609.04, Determining the Significance of Reactor Inspection Findings for at-power Situations, the inspectors conducted a Phase 1 screen and determined the finding to be of very low safety significance (Green) because the finding did not represent an actual open pathway in the physical integrity of reactor containment isolation system and heat removal components, did not involve an actual reduction in function of hydrogen igniters in containment, and did not screen as potentially risk significant due to external initiating events.

This finding has a cross-cutting aspect in the area of human resources because PSEG did not provide complete and accurate procedures for the performance of this surveillance test H.2(c). Specifically, the continuous use procedure Service Water Fouling Monitoring Containment Fan Coil Units, revised on May 31, 2008, did not contain procedure steps to direct the opening and closing of valves that must be manipulated to successfully perform the procedure. (Section 1R22)

Licensee Identified Violations

None.

REPORT DETAILS

Summary of Plant Status

Salem Nuclear Generating Station Unit 1 (Unit 1) began the period at 93% power to support offsite transmission line maintenance. On April 1, 2008, operations returned Unit 1 to full power.

On April 3, operations reduced power to 93% because a fire off site posed a risk to one of two operable transmission lines. Operations returned Unit 1 to full power on April 4. On April 20, operations reduced power to 55% because a fire off site posed a risk to one of two available transmission lines. In this instance, the transmission line was de-energized until the fire was extinguished. The line was subsequently returned to service and operations returned Unit 1 to full power on April 21. On April 26, operations reduced power to 93% because thunderstorms posed a risk to transmission grid stability. Operations returned Unit 1 to full power on April 27 and Unit 1 operated at full power for the remainder of the inspection period.

Salem Nuclear Generating Station Unit 2 (Unit 2) began the period defueled with the reactor coolant system drained to support steam generator replacement during the sixteenth refueling outage of Unit 2 (S2R16). Operations returned Unit 2 to service on May 8 and achieved 48%

power before reducing power and tripping the main turbine in response to a loss of circulating water on May 9. Operations then manually tripped the reactor in response to a high steam generator water level in the 23 steam generator. Operations restarted Unit 2 on May 10 and achieved 84% power on May 12. On May 12 operations shutdown Unit 2 because PSEG determined all high steam flow protection channels were inoperable. PSEG restarted Unit 2 on May 16. Operations achieved full power on May 21 with Unit 2 power limited to 98.2% by main turbine governor valve limitations. Unit 2 remained at full power with electrical output limited by governor valve limitations for the remainder of the period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems and Barrier Integrity

1R01 Adverse Weather Protection

.1 Summer Readiness of Offsite and Alternate AC Power Systems

a. Inspection Scope

The inspectors completed one adverse weather inspection sample to evaluate the readiness of offsite power to the Salem units prior to the summer season when electrical grid stability can be most challenged. The inspectors verified that PSEG provided procedure requirements or guidance to monitor and maintain availability and reliability of the offsite AC power (OSP) system prior to and during adverse weather conditions.

Specifically the inspectors verified that the procedures addressed:

• The actions to be taken when notified by the Electrical System Operations Center (ESOC) of the PJM interconnection that the post-trip voltage of the OSP system at Salem will not be acceptable to assure the continued operation of the safety-related loads without transferring to the emergency diesel generators.

• The compensatory actions to be performed if ESOC cannot predict the post-trip voltage.

• Re-assessment of plant risk for maintenance activities that could affect grid reliability or OSP system availability to the Salem units.

• Communication requirements between Salem and the ESOC regarding plant changes that could impact the transmission system, or the capability of the transmission system to provide adequate OSP.

The inspectors also reviewed PSEGs seasonal readiness preparations for the summer season specific to the main power transformers and the OSP system. The inspectors interviewed engineering and work control personnel and reviewed work orders and completed portions of WC-AA-107, Seasonal Readiness, Revision 7 to verify that PSEG took measures to ensure the reliability of the main power transformers and the OSP system during the summer season. The documents reviewed during this inspection are listed in the Attachment.

b. Findings

No findings of significance were identified.

.2 Readiness for Impending Adverse Weather Conditions

a. Inspection Scope

The inspectors completed one adverse weather inspection sample to evaluate Salem Generating Stations readiness and response to emergent high water levels in the Delaware River. The inspectors verified that the station took appropriate preplanned action per SC.OP-AB.ZZ-0001, Adverse Environmental Conditions. Further, the inspectors evaluated the condition of water tight doors and cover plates required by technical specifications.

b. Findings

No findings of significance were identified.

.3 Readiness for Seasonal Extreme Weather Conditions

a. Inspection Scope

The inspectors completed one adverse weather inspection sample for the onset of hot weather. The inspectors reviewed hot weather preparations to verify PSEG adequately prepared equipment to operate reliably in extreme hot weather conditions. Specifically, the inspectors interviewed engineering and operations personnel, and walked down the service water intake structure (SWIS), the switchyard, and the switchgear & penetration area ventilation (SPAV) system. The inspectors verified that design features used to maintain these systems functional during hot weather conditions were adequately maintained. The documents reviewed during this inspection are listed in the Attachment.

b. Findings

No findings of significance were identified.

1R04 Equipment Alignment

Partial Walkdown

a. Inspection Scope

The inspectors completed four partial system walk down inspection samples. The inspectors walked down the systems 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 corrective action program 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 Attachment. The inspectors walked down the systems listed below:

• The Unit 1 and 2 control area air conditioning (CAACS) and control room emergency air conditioning (CREACS) systems following restoration to the normal alignment from the maintenance mode alignment with Unit 2 CREACS out of service on April 8;

• The Unit 2 residual heat removal (RHR) system prior to return to service following steam generator replacement during Unit 2 refueling outage S2R16 on April 17;

• The Unit 2 service water (SW) cooling for all three emergency diesel generators (EDGs) following completion of EDG maintenance during refueling outage S2R16 on April 22; and

• The Unit 1 SW system with the 12 service water pump out of service for maintenance on June 10.

b. Findings

No findings of significance were identified.

1R05 Fire Protection

.1 Quarterly Review of Fire Areas

a. Inspection Scope

The inspectors completed eight fire protection quarterly inspection samples. The inspectors performed walk downs to assess the material condition and operational status of fire protection features. The inspectors verified that combustibles and ignition sources were controlled in accordance with PSEGs administrative procedures; fire detection and suppression equipment was available for use; that passive fire barriers were maintained in good material condition; and that compensatory measures for out-of-service, degraded, or inoperable fire protection equipment were implemented in accordance with PSEGs fire plan. Documents reviewed are listed in the Attachment. The inspectors evaluated the fire protection areas listed below:

• Unit 1 and 2 service water intake structure (SWIS);

• Unit 1 and 2 outer penetration areas;

• Unit 1 and 2 auxiliary ventilation unit areas;

• Unit 2 Reactor Containment; and

• Unit 2 Reactor Plant Auxiliary Equipment Area, Elevations 45 & 55.

b. Findings

No findings of significance were identified.

1R07 Heat Sink Performance

a. Inspection Scope

The inspectors reviewed performance data and interviewed the program manager responsible for implementation of NRC Generic Letter (GL) 89-13 to verify that potential heat exchanger (HX) or heat sink deficiencies were identified and that PSEG adequately resolved heat sink performance problems. Specifically, the inspectors reviewed 21 component cooling water (CCW) HX data. Inspectors evaluated trending data and verified that equipment would perform satisfactorily under design basis conditions. The method of performance monitoring was compared against NRC GL 89-13, Service Water System Problems Affecting Safety-Related Equipment,, and EPRI NP 7552, Heat Exchanger Performance Monitoring Guidelines, for conformance to these guidance documents.

The inspectors walked down the selected components and the SW intake structure to assess the general material condition of the selected HXs and the associated SW components. The inspectors also inspected the internal components of 21 CCW HX, that was open for preventive maintenance, and observed the type and quantity of material present in the HX. Documents reviewed are listed in the Attachment.

b. Findings

No findings of significance were identified.

1R08 Inservice Inspection Activities

a. Inspection Scope

The inspectors observed a selected sample of nondestructive examination (NDE)activities in process. The inspectors also reviewed selected additional samples of completed NDE and repair/replacement activities. The sample selection was based on the inspection procedure objectives and risk priority of those components and systems where degradation would result in a significant increase in the risk of core damage. The observations and documentation reviews were performed to verify the activities described were performed in accordance with the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code requirements. The inspectors reviewed a sample of inspection reports and condition reports (Notifications) initiated as a result of issues identified during inservice inspection (ISI) activities. Also, the inspectors evaluated the effectiveness of the resolution of problems identified during selected ISI activities.

The inspectors reviewed PSEG=s boric acid corrosion control program. The inspectors observed PSEG=s boric acid walkdown inspection process inside containment at the beginning of the Unit 2 refueling outage. The inspectors verified that the walkdown inspections were thorough and that indications of boric acid leakage were recorded and evaluated in accordance with PSEG=s program for documentation in the corrective action (Notification) process. Additionally, the inspectors reviewed a sampling of notifications for correct evaluation and/or further engineering analysis and/or final resolution.

The inspectors observed the performance of one in-process NDE activity and reviewed documentation and examination reports for an additional 22 NDE activities. The inspectors reviewed seven samples of welding activities on reactor coolant system pressure boundary components and, reviewed the work packages for five repair efforts performed in accordance with the ASME Code during previous operating cycles. These observations and reviews covered ultrasonic, visual, penetrant and radiographic NDE processes.

The inspectors reviewed inspection data sheets and documentation for manual ultrasonic testing (UT) activities to verify the effectiveness of the examiner, process, and equipment to identify degradation of risk significant systems, structures and components and to evaluate the activities for compliance with the requirements of ASME Code,Section XI. The inspectors reviewed a sample of work orders for repairs made to plant components to evaluate compliance with the requirements of the ASME Code,Section XI.

The inspectors reviewed one sample of an NDE evaluation that was initially rejected and subsequently accepted after evaluation. The inspectors also reviewed the radiographs and the examiners= interpretation of indications on several reactor coolant system welds, one main steam system weld and two feedwater system welds. These activities were performed during steam generator replacement activities.

During this refueling outage the PSEG replaced the original plant Steam Generators with new replacement steam generators provided by AREVA. The inspection of the Steam Generator Replacement activities was conducted in accordance with Inspection Procedure 50001, Steam Generator Replacement Activities. During this refueling outage, PSEG did not conduct any steam generator eddy current inspections.

b. Findings

No findings of significance were identified.

1R11 Licensed Operator Requalification Program

a. Inspection Scope

The inspectors completed one quarterly licensed operator requalification program inspection sample. Specifically, the inspectors observed simulator training of licensed operators on June 16, 2008. The simulated scenario involved grass loading on circulating water (CW) traveling water screens that caused a loss of two CW pumps with a third CW pump out of service for maintenance, followed by a loss of main turbine lube oil that required a turbine shutdown, followed by a failed open main steam safety valve that required operators to trip the reactor and isolate the affected main steam line.

The inspectors assessed simulator fidelity and observed the crews and the simulator instructors critiques of operator performance. Documents reviewed are listed in the

.

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 two systems. The inspectors reviewed PSEGs 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 tracked by PSEG to evaluate the effectiveness of PSEGs condition monitoring activities and to determine whether performance goals were met. The inspectors reviewed applicable work orders, corrective action notifications, and preventive maintenance tasks. The documents reviewed are listed in the Attachment. The inspectors evaluated the systems listed below:

• Unit 2 pressurizer (PZR) pilot operated relief valve (PORV) backup control air accumulator check valves, 2CA1785, 2CA1786, 2CA1787 and 2CA1788; and

• Unit 1 and 2 control room ventilation intake radiation monitors, 1R1A/B and 2R1A/B.

b. Findings

No findings of significance were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

The inspectors completed seven maintenance effectiveness and emergent work control inspection samples. The inspectors reviewed the maintenance activities 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. PSEGs risk management actions were reviewed during shift turnover meetings, control room tours, and plant walk downs. The inspectors also used PSEGs on-line risk monitor (Equipment Out-Of-Service workstation) to gain insights into the risk associated with these plant configurations. The inspectors reviewed notifications documenting problems associated with risk assessments and emergent work evaluations. Documents reviewed are listed in the Attachment. The inspectors assessed the plant configurations listed below:

• Planned unavailability of the 22 component cooling water (CCW) heat exchanger following a full core offload to the spent fuel pit (SFP) during Unit 2 refueling outage S2R16 concurrent with unavailability of the 5021 offsite transmission line;

• Emergent unavailability of the 23 chiller concurrent with degradation of the 21 chiller controls and unavailability of the 5021 offsite transmission line;

• Planned unavailability of the Unit 2 control room emergency air conditioning system and unavailability of the 5021 offsite transmission line;

• Planned unavailability of the 2 and 12 station power transformers (SPT) followed by restoration of the 2 SPT and planned unavailability of the station gas turbine generator;

• Troubleshooting Unit 2 pressurizer (PZR) pilot operated relief valve (PORV) leakage that included blocking both PZR PORVs;

• Emergent unavailability of the station blackout control air compressor; and

• Unplanned unavailability of all three Unit 2 chillers.

b. Findings

Introduction:

A self-revealing non-cited violation of Technical Specification (TS) 6.8.1.a, Procedures and Programs, was identified because PSEG did not maintain adequate control of the system configuration for the Unit 2 chill water system during maintenance on the 21 chiller. Specifically, on May 27, 2008, all three Unit 2 chill water system chillers tripped due to an error in the safety tagging sequence specified by the work control documents for maintenance on the 21 chiller. This finding was determined to be of very low safety significance (Green).

Description:

The Unit 2 chill water system consists of three 50% capacity chillers. The system provides cooling for the control and relay rooms and is the normal cooling supply for the emergency control air compressors. A loss of cooling to the emergency control air compressor could result in a loss of control air leading to a complicated plant trip.

During the safety tagging evolution that aligned the chill water system for the corrective maintenance on the 21 chiller, all three Unit 2 chillers tripped due to low water level in the chilled water expansion tank. This resulted in a loss of forced cooling for the relay room and the emergency control air compressor. Due to low outside air temperatures, temperatures in the relay room remained stable. The emergency control air compressor was not operating and control room cooling was provided by the Unit 1 chillers.

Operators subsequently recovered chill water expansion tank level and restored the Unit 2 chill water system to service.

PSEG conducted an investigation and determined that the work control document (WCD) used for tagging the 21 chiller for maintenance included an incorrect tagging sequence. The original WCD for this maintenance properly sequenced the tagging evolution to isolate the 21 chiller prior to opening the chill water system drain valves, but before initiating the WCD, operators attempted to simplify the tagging process by grouping the service water components and the chilled water components together.

When simplifying the tagging process the work center supervisor did not complete the initiation and pre-approval process as required by work control procedures. Specifically the work center supervisor did not implement the procedure step for WCD review and pre-approval that stated, If changes are required, then return the tagging package to the initiator ..., and ... ensure WCD changes are forwarded for field verification. As a result the chill water drains were tagged open prior to closing and tagging the chill water outlet valve on the 21 chiller. This resulted in draining the system and a low water level in the chill water expansion tank that caused the loss of all three Unit 2 chillers.

PSEGs corrective actions included training for the operators involved in this event. The training reinforced the procedural requirement for independent checks of all pre-approved work control documents that are modified in any manner.

Analysis:

PSEG did not perform independent checks of the WCD following completion of revisions to the tagging sequence for the 21 chiller. The inspectors determined that this was a performance deficiency because procedure SH.OP-AP.ZZ-0051, Safety Tagging Operations, required that the revised WCD be returned to the initiator for review and forwarded for field verification, but these steps were not completed. This performance deficiency is more than minor because it is associated with the configuration control attribute of the Initiating Events cornerstone, and it adversely affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, unavailability of all three chillers increased the likelihood of a loss of control air that could result in a complicated plant trip. Per Inspection Manual Chapter (IMC) 0609, Attachment 0609.04, initial screening and characterization of findings, the inspectors conducted a Phase 1 analysis and determined that this finding required a Phase 2 analysis because the finding contributed to both the likelihood of a reactor trip and the likelihood that mitigation equipment or functions will not be available.

The inspectors determined that the finding was of very low safety significance (Green)using the Salem plant specific Phase 2 pre-solved worksheets in accordance with IMC 0609, Appendix A, Determining the Significance of Reactor Inspection Findings for At-Power Situations. The estimated increase in core damage frequency was approximately 1 in 100,000,000 (actual was E-8) assuming the reactor was operating at full power and all three chillers were out of service for two hours which resulted in an increase in the loss of control air (LCA) initiating event frequency. An evaluation of the Salem plant specific Phase 2 pre-solved worksheets showed that two sequences were dominant. The first involved a LCA with a failure of the following components/functions:

Station blackout compressor, auxiliary feedwater, and high pressure recirculation. The second involved a LCA with the failure of the following components/functions: Station blackout compressor, auxiliary feedwater, and feed and bleed. Service water has the ability to be manually aligned to the Unit 2 control air compressor through a spool piece and was available throughout the event and could have provided some mitigation capability.

This finding has a cross-cutting aspect in the area of human performance because PSEG personnel did not follow procedures H.4(b). Specifically, revisions to the work control document for tagging the 21 chiller did not comply with the requirements of PSEG procedure SH.OP-AP.ZZ-0051, Safety Tagging Operations.

Enforcement:

Technical Specification 6.8.1.a requires the establishment, implementation and maintenance of written procedures recommended in Appendix A of Regulatory Guide 1.33, Revision 2, February 1978. Regulatory Guide 1.33, Appendix A, Section 1 recommends administrative activities, including equipment control (e.g.,

locking and tagging) be covered by written procedures. PSEG procedure SH.OP-AP.ZZ-0051, Safety Tagging Operations, requires that when revising an approved tagging package, the initiator, the qualified operator, and the approving supervisor each review blocking points for adequacy. Contrary to the above, when revising an approved work control document to hang tags in preparation for performing maintenance on the 21 chiller, work control personnel did not ensure the required reviews and approvals were completed. As a result the chill water drains were tagged open prior to closing the chill water outlet valve on the 21 chiller. This caused the system to drain and a low water level in the chill water expansion. When the chill water expansion tank drained the two operating chillers tripped and there were no operable chillers on Unit 2 for a period of two hours on May 27, 2008. Because this finding is of very low safety significance and has been entered into the corrective action program in notification 20371577, this violation is being treated as a NCV, consistent with section VI.A of the NRC Enforcement Policy. (NCV 05000311/2008003-01, Salem Unit 2 Loss of All Three Chillers)

1R15 Operability Evaluations

a. Inspection Scope

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

• Restoration of the Unit 1 and 2 control room envelope (CRE) to operability following emergent failure of radiation monitor 1R1B-2;

• 13 containment fan coil unit (CFCU) following unsatisfactory computed biofouling margin in the 13 CFCU motor cooler;

• Unit 2 service water system following incorrect installation of WEKO seal backing rings throughout the system during S2R16;

• Unit 2 reactor vessel level indication system (RVLIS) following a refueling outage that included steam generator replacement;

• Unit 1 reactor protection system (RPS) given a 6% mismatch between indicated steam flow and feedwater flow;

• Unit 2 RPS given a mismatch of up to 14% between indicated steam flow and feedwater flow;

• The 13 component cooling water (CCW) pump with an oil leak from the outboard pump bearing; and

• The 21 and 22 safety injection (SJ) pumps with high vibrations when the pumps were operated at full flow during technical specification surveillance testing.

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 PSEGs operability determinations.

Additionally, the inspectors reviewed other PSEG identified safety-related equipment deficiencies during this report period and assessed the adequacy of their operability screenings. Documents reviewed are listed in the Attachment.

a. Findings

Introduction:

A self-revealing non-cited violation of Technical Specification (TS) 6.8.1.a, Procedures and Programs, was identified because PSEG did not adequately maintain the calibration of the Unit 2 reactor vessel level indication system (RVLIS). Specifically, scaling for both RVLIS dynamic range channels was not completed when required. This resulted in Unit 2 RVLIS being inoperable for 13-days. This finding was determined to be of very low safety significance (Green).

Description:

The RVLIS measures reactor vessel water level when reactor coolant pumps are off and relative reactor coolant void content, dynamic range indication, when reactor coolant pumps are running. Inaccurate RVLIS indication could cause operators to take non-conservative actions during an inadequate core cooling or loss of coolant inventory event. The purpose of the RVLIS scaling procedure is to verify proper calibration of the RVLIS dynamic range indication. The procedure is performed on an 18-month frequency following each refueling outage. The scaling procedure records operating data for the plant during heat up after each refueling outage. The data is used to calculate dynamic head curve coefficients that are then used by RVLIS to determine dynamic range indication.

On May 20, 2008, both channels of RVLIS dynamic range indication began to indicate high off scale as Unit 2 approached full power after its refueling outage. As a result, operators declared both channels of RVLIS dynamic range inoperable per Technical Specification 3.3.3.7 and implemented compensatory measures.

PSEG conducted an apparent cause evaluation and determined that data obtained during plant heat up indicated that new dynamic head curve coefficients needed to be entered into the system to ensure accurate RVLIS indication. Maintenance personnel did not complete RVLIS dynamic range scaling in accordance with SC.IC-PT.RVL-0001, RVLIS Level Output Scaling Adjustments and Heat-up Data Collection, before a maintenance supervisor inappropriately closed the associated work order on May 7.

Technicians had recorded the required plant operating data and were provided the new dynamic range head curve coefficients before May 8, but did not enter the new coefficients into RVLIS until after the RVLIS dynamic range indicated high off scale on May 20. Inadequate work coordination between Operations, Maintenance, and Engineering caused plant operators to believe that RVLIS was operable even after an engineer discovered that the new dynamic head coefficients had not been entered. On May 8 the engineer, who knew the coefficients were required to maintain RVLIS indication accurate, consulted with the responsible maintenance supervisor and initiated a new work order to install the coefficients. However, because the knowledgeable engineer did not emphasize the importance of entering the new coefficients through discussions and because the work order did not accurately describe the impact on operability, the operators did not recognize that this work was important to RVLIS operability. The operators denied permission for a maintenance technician to install the new coefficients under the new work order because the control room was busy with plant startup activities. As a result, the new coefficients were not installed until May 20 after operators discovered that RVLIS was inoperable because dynamic range indication began to indicate off scale.

PSEG entered this issue into the CAP and implemented several corrective actions that included a review of the status of other safety-related work completed by the applicable maintenance supervisor to verify accurate work documentation; procedure enhancements to both maintenance and operations procedures; and personnel actions to enforce standards, improve teamwork and enhance communications through shift turnover.

Analysis:

PSEG did not complete RVLIS scaling in accordance with SC.IC-PT.RVL-0001, RVLIS Level Output Scaling Adjustments and Heat-up Data Collection. The inspectors determined that this was a performance deficiency because the original work order and the RVLIS scaling procedure directed that the procedure, including entry of the new coefficients, be completed. As a result, operators were not aware that both channels of RVLIS were inoperable for more than 13-days. The performance deficiency is more than minor because it is associated with the equipment performance attribute of the Mitigating Systems cornerstone and because it affected the cornerstone objective of ensuring the reliability of systems that respond to initiating events to prevent undesirable consequences. Specifically, operators were not aware that both channels of RVLIS were inoperable and could have taken non-conservative actions during an inadequate core cooling or loss of coolant inventory event. Per inspection manual chapter (IMC)0609.04, Initial Screening and Characterization of Findings, the inspectors conducted a Phase 1 screen and determined the finding to be of very low safety significance (Green)because the performance deficiency was not a design deficiency, did not result in an actual loss of safety function, and did not screen as potentially risk significant due to external initiating events.

This performance deficiency has a cross-cutting aspect in the area of human performance because PSEG did not appropriately coordinate work activities as necessary to keep personnel apprised of work status and the operational impact of work activities. Specifically, PSEG did not ensure RVLIS scaling was completed per the established work control process because engineering did not adequately communicate the importance of entering the new dynamic range coefficients to support operability of the RVLIS system. H.3(b)

Enforcement:

Technical Specification 6.8.1.a requires establishment, implementation and maintenance of written procedures recommended in Appendix A of Regulatory Guide 1.33, Revision 2, February 1978. Regulatory Guide 1.33, Appendix A, Section 9 requires that maintenance affecting the performance of safety-related equipment be performed per written procedures, documented instructions or drawings appropriate to the circumstances. Contrary to the above, on May 7, 2008, PSEG collected required data, obtained new dynamic range head curve coefficients, but did not complete the RVLIS scaling procedure by entering the coefficients into the RVLIS system.

Consequently, accident monitoring instrumentation required by technical specifications was inoperable for approximately 13-days. Because this finding is of very low safety significance and has been entered into the corrective action program in notification 20371034, this violation is being treated as a NCV, consistent with section VI.A of the NRC Enforcement Policy. (NCV 05000311/2008003-02, Salem Unit 2 Loss of Reactor Vessel Level Indication System)

1R18 Plant Modifications

.1 Temporary Modification

a. Inspection Scope

The inspectors completed one plant modification inspection sample. The inspectors reviewed Temporary Configuration Change Package (TCCP)-08-002 for the 15 service water pump packing arrangement. This configuration change altered the packing arrangement in the stuffing box due to wear on the installed shaft sleeve. The inspectors review included system walk downs and comparison of the temporarily modified configuration to the UFSAR description. Inspectors reviewed the 10 CFR 50.59 screening against the system design basis documentation, and verified that the modifications did not affect system operability.

b. Findings

No findings of significance were identified.

.2 Permanent Modification

a. Inspection Scope

The inspectors completed one plant modification inspection sample. The inspectors reviewed permanent modifications to the Salem Unit 2 Containment Fan Coil Unit (CFCU) service water flow control under change number DCP 80089131. This review included system walk downs, interviews with plant engineers, and functional comparison of the new control scheme to the UFSAR description. The inspectors also reviewed design adequacy of the modification, preparation, staging, and implementation of the modification, and post modification testing.

This modification replaced a system that varied service water flow for normal and accident conditions with a simplified scheme that provided a fixed resistance service water flow to the CFCUs under normal and accident conditions. This modification simplified the SW system and eliminated numerous components and instruments that had active safety functions. This modification was made following approval of License Change Request S06-10. Each of the five CFCUs located in the Unit 2 containment were included in this permanent modification. This modification was performed during the Unit 2 refuel outage (2R16).

b. Findings

No findings of significance were identified.

1R19 Post-Maintenance Testing

a. Inspection Scope

The inspectors completed seven post-maintenance testing inspection samples. The inspectors observed portions of and/or reviewed the results of the post-maintenance test activities. 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. The inspectors evaluated the post-maintenance tests for the maintenance items listed below:

• Work order (WO) CM980824163, 2A emergency diesel generator (EDG) K1C relay replacement;

• WO 60054063, weld repairs to the 22 component cooling heat exchanger (CCHX) north cover liner;

• WO 60076709, replacement of 2N43 power range neutron detector;

• WO 60076388 and 60076389, adjustment of 21SJ44 and 22SJ44 stroke times and valve leakage troubleshooting;

• WO 80083522, main steam flow protection and indication following replacement of Unit 2 steam generators and high pressure turbine;

• WO 30145027, reactor vessel level instrumentation system (RVLIS) return to service following replacement of Unit 2 steam generators; and

• WO 30126880, 1A1 28 volt DC battery charger following 18 month preventive maintenance including replacement of selected charger circuit cards and filter capacitors.

b. Findings

No findings of significance were identified.

1R20 Refueling and Other Outage Activities

a. Inspection Scope

Unit 2 Refueling Outage. The inspectors observed and/or reviewed the following refueling outage activities to verify that operability requirements were met and that risk, industry experience, and previous site specific problems were considered. Documents reviewed for this inspection are listed in the Attachment.

The inspectors reviewed the schedule and risk assessment documents associated with the Unit 2 refueling outage to confirm that PSEG appropriately considered risk, industry experience, and previous site-specific problems in developing and implementing a plan that assured maintenance of defense-in-depth systems and barriers. Prior to the refueling outage the inspectors reviewed PSEG=s outage risk assessment to identify risk significant equipment configurations and determine whether planned risk management actions were adequate. During the refueling outage the inspectors verified that PSEG managed the outage risk commensurate with the outage plan.

The inspectors observed portions of the shutdown and cool down processes and monitored PSEG controls over the outage activities. The inspectors also verified that cool down rates were within technical specification limitations.

The inspectors observed conditions within containment for indications of unidentified leakage and damaged equipment.

The inspectors periodically observed refueling activities from the refueling bridge in containment and the spent fuel pool to verify refueling gates and seals were properly installed and determine whether foreign material exclusion boundaries were established around the reactor cavity. Core offload and reload activities were periodically observed from the control room and refueling bridge to verify whether operators adequately controlled fuel movements in accordance with procedures.

The four Unit 2 steam generators were replaced during this refuel outage. The old steam generators were removed and new steam generators were installed through the containment equipment hatch. Inspection of these specific activities is discussed in section 4OA5.

The inspectors verified that tagged equipment was properly controlled and equipment configured to safely support maintenance work. Specifically, tags hung in containment to support the steam generator replacement were checked for accuracy of the tag versus the label, as well as the valve position specified.

Equipment work areas were periodically observed to determine whether foreign material exclusion boundaries were adequate.

During control room tours, the inspectors verified that operators maintained adequate reactor coolant system (RCS) level and temperature and that indications were within the expected range for the operating mode.

The inspectors verified that offsite and onsite electrical power sources were maintained in accordance with TS requirements and consistent with the outage risk assessment.

Periodic walk downs of portions of the switchyard, onsite electrical buses and the EDGs were conducted during risk significant electrical configurations.

The inspectors verified through routine plant status activities that the decay heat removal safety function was maintained with appropriate redundancy as required by TS and consistent with PSEG=s outage risk assessment. During core offload conditions, the inspectors periodically determined whether the fuel pool cooling system was performing in accordance with applicable TS requirements and consistent with PSEG=s risk assessment for the refueling outage.

The inspectors observed the Unit 2 RCS draining to the mid-loop condition on April 27, 2008. RCS inventory controls and contingency plans were reviewed by the inspectors to determine whether they met TS requirements and provided for adequate inventory control. The inspectors reviewed procedures and observed portions of activities in the control room when the unit was in reduced inventory modes of operation, including mid-loop operations. The inspectors verified that level and core temperature measurement instrumentation was installed and operational. Calculations that provide time-to-boil information were also reviewed for RCS reduced inventory conditions as well as the spent fuel pool during increased heat load conditions.

Containment status and procedural controls were reviewed by the inspectors during fuel offload and reload activities to verify that TS requirements and procedure requirements were met for containment. Specifically, the inspectors verified that during fuel movement activities, personnel, materials and equipment were staged to close containment penetrations as specified in the licensing basis.

The inspectors conducted a thorough walk down of containment prior to reactor startup.

Areas of containment where work was completed were inspected for evidence of leakage and to ensure debris that could block containment sumps was removed.

Portions of mode changes and reactor startup were observed and reviewed for compliance with applicable procedures and TS.

b. Findings

No findings of significance were identified.

1R22 Surveillance Testing

a. Inspection Scope

The inspectors completed seven 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 TS requirements, the UFSAR, and ASME Section XI for pump and valve testing. Documents reviewed are listed in the

. The inspectors evaluated the surveillance tests listed below:

• SC.MD-EU.CRN-0013, Fuel Handling Crane Daily Use Inspection, during Unit 2 core reload activities;

• S2.OP-ST.SJ-0021, RCS Pressure Isolation Leakage Test 2RH1 and 2RH2 Valves (Containment Isolation Valves (CIV));

• S2.OP-ST.MS-0003, Steam Line Isolation and Response Time Testing;

• S2.OP-ST.AF-0003, Inservice Testing - 23 Auxiliary Feedwater Pump (IST);

• S2.OP-ST.AF-0006, Inservice Testing - Auxiliary Feed Water Valves;

• S2.OP-ST.AF-0009, Plant Systems - Auxiliary Feedwater; and

• S2.OP-ST.SJ-0020, Periodic Leakage Test, RCS Pressure Isolation Valves (CIV).

b. Findings

Introduction:

A self-revealing non-cited violation of Technical Specification (TS) 6.8.1.a, Procedures and Programs, was identified because the 22 Containment Fan Coil Unit (CFCU) had cooling water flow to the motor cooler inadvertently isolated during a routine surveillance test. Specifically, the surveillance procedure did not include steps to operate specific gage isolation valves to place a gage in service, and as a result technicians repositioned the wrong valves. This finding was determined to be of very low safety significance (Green).

Description:

The Unit 2 containment cooling system consists of five CFCUs designed to maintain containment temperature below design temperature limits during normal operation, and maintain containment pressure below design pressure limits during accident conditions by condensing steam vapor in the containment.

During the performance of a surveillance test on the 22 CFCU, technicians measured zero service water flow through the 22 CFCU motor cooler. The technicians immediately notified the control room and operators declared the 22 CFCU inoperable and subsequently removed it from service.

PSEG conducted an investigation of the event and determined that one of two technicians assigned to perform the surveillance testing had inadvertently closed the 22 CFCU motor cooler service water inlet and outlet valves while attempting to place a differential pressure gage, installed to collect test data, in service. Both of these valves were normally locked open, but the technician was able to reposition them without removing the locks. PSEG determined through its review that the continuous use procedure Service Water Fouling Monitoring Containment Fan Coil Units that was used to complete the testing did not contain specific steps that identified the valves that the technicians needed to open to place the differential pressure gage in service. Due to the lack of information provided in the procedure, the technician relied on his knowledge and training for the system to identify those valves. As a result the technician incorrectly shut the locked open motor cooler service water inlet and outlet isolation valves, which rendered the 22 CFCU inoperable.

Corrective actions taken by PSEG were to immediately restore the cooler isolation valves to their correct positions and to revise the surveillance procedure to add individual signoff steps for each valve manipulation and action taken. In addition, because the valves that were repositioned were locked valves, PSEG also performed a check of all locked valves on Unit 2 to verify compliance with the requirements of the locked-valve program.

Analysis:

The procedure used to perform surveillance testing on the 22 CFCU did not contain procedure steps that directed technicians to open valves to place a differential pressure gage in service. As a result a technician inadvertently closed two normally locked open valves that isolated cooling water flow to the CFCU. The inspectors determined that this was a performance deficiency because TS 6.8.1.a requires the establishment, implementation and maintenance of adequate written procedures for operations discussed in Appendix A of Regulatory Guide 1.33, Revision 2, February 1978. The issue was within PSEGs ability to foresee and correct because PSEG recently revised the procedure, but did not ensure that it conformed to continuous use procedure standards. This finding is more than minor because it is associated with the system, structure, and component (SSC) and barrier performance attribute of the Barrier Integrity cornerstone and it affects the cornerstone objective of providing reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. Specifically, unavailability of the 22 CFCU represented an actual loss of defense in depth of a system that controls containment pressure. Per inspection manual chapter (IMC) 0609, Attachment 0609.04, Determining the Significance of Reactor Inspection Findings for at-power Situations, the inspectors conducted a Phase 1 screen and determined the finding to be of very low safety significance (Green) because the finding did not represent an actual open pathway in the physical integrity of reactor containment isolation system and heat removal components, did not involve an actual reduction in function of hydrogen igniters in containment, and did not screen as potentially risk significant due to external initiating events.

This finding has a cross-cutting aspect in the area of human resources because PSEG did not provide complete and accurate procedures for the performance of this surveillance test H.2(c). Specifically, the continuous use procedure Service Water Fouling Monitoring Containment Fan Coil Units, revised on May 31, 2008, did not contain procedure steps to direct the opening and closing of valves that must be manipulated to successfully perform the procedure.

Enforcement:

Technical Specification 6.8.1.a requires the establishment, implementation and maintenance of written procedures recommended in Appendix A of Regulatory Guide 1.33, Revision 2, February 1978. Regulatory Guide 1.33, Appendix A, Section 8 recommends that specific procedures be written for surveillance tests, inspections and calibrations. Contrary to the above, PSEG procedure S2.OP-PT.SW-0007, Service Water Fouling Monitoring Containment Fan Coil Units, was inadequate for performing surveillance testing on the 22 CFCU. Cooling water flow to the 22 CFCU motor cooler was inadvertently isolated, resulting in one hour of unavailability of the 22 CFCU on June 4, 2008. Because this finding is of very low safety significance and has been entered into the corrective action program in notification 20372695, this violation is being treated as a NCV, consistent with section VI.A of the NRC Enforcement Policy.

(NCV 05000311/2008002-03, Salem Unit 2 22 CFCU Valves Mispositioned)

RADIATION SAFETY

Cornerstone: Occupational Radiation Safety

2OS1 Access Control to Radiologically Significant Areas (71121.01 - 8 samples)

a. Inspection Scope

Based on PSEGs schedule of work activities during the Unit 2 refueling outage (S2R16),the inspectors selected three jobs (reactor disassembly, reactor coolant pump motor replacement, in-service inspection) performed in radiation areas, airborne radioactivity areas, or high radiation areas (<1 R/hr) for observation. The inspectors observed work that was estimated to result in the highest collective doses, involved diving activities in or around spent fuel or highly activated material, or that involved potentially changing (deteriorating) radiological conditions. The inspectors reviewed all radiological job requirements (radiation work permit requirements and work procedure requirements).

The inspectors observed job performance with respect to these requirements and verified that radiological conditions in the work area were adequately communicated to workers through briefings and postings.

During job performance observations, the inspectors verified the adequacy of radiological controls, such as: required surveys (including system breach radiation, contamination, and airborne surveys), radiation protection job coverage (including audio and visual surveillance for remote job coverage), and contamination controls.

For high radiation work areas with significant dose rate gradients (factor of 5 or more), the inspectors reviewed the application of dosimetry to effectively monitor exposure to personnel.

During job performance observations, the inspectors observed radiation worker performance with respect to stated radiation protection work requirements. The inspectors verified that they were aware of the significant radiological conditions in their workplace, the radiation work permit controls/limits in place, and that their performance took into consideration the level of radiological hazards present.

During job performance observations, the inspectors observed radiation protection technician performance with respect to all radiation protection work requirements. The inspectors verified that they were aware of the radiological conditions in their workplace and the radiation work permit controls/limits, and if their performance was consistent with their training and qualifications with respect to the radiological hazards and work activities.

The inspectors identified exposure significant work areas within radiation areas, high radiation areas (<1 R/hr), or airborne radioactivity areas in the plant and review associated PSEG controls and surveys of these areas to determine if controls (e.g.,

surveys, postings, barricades) were acceptable. The areas reviewed by the inspectors included the containment, auxiliary building and spent fuel building. With a survey instrument, the inspectors walked down these areas or their perimeters to determine:

whether prescribed radiation work permits, procedure, and engineering controls were in place, whether PSEG surveys and postings were complete and accurate, and whether air samplers were properly located.

The inspectors reviewed radiation work permits used to access these and other high radiation areas and identify what work control instructions or control barriers were specified. The inspectors used plant-specific TS high radiation area requirements as the standard for the necessary barriers. The inspectors reviewed electronic personal dosimeter alarm set points (both integrated dose and dose rate) for conformity with survey indications and plant policy. The inspectors verified that workers know what actions are required when their electronic personal dosimeter noticeably malfunctions or alarms.

The inspector evaluated PSEG performance against the requirements contained in 10 CFR 20, and Unit 2 Technical Specification 6.12.

b. Findings

No findings of significance were identified.

2OS2 ALARA Planning and Controls (71121.02 - 4 samples)

a. Inspection Scope

The inspectors obtained from PSEG a list of work activities ranked by actual/estimated exposure that were in progress during the current outage (2R16) and selected the three work activities of the highest exposure significance (see section 2OS1 above).

The inspectors reviewed the ALARA work activity evaluations, exposure estimates, and exposure mitigation requirements. The inspectors verified that PSEG had established procedures, and engineering and work controls that were based on sound radiation protection principles, to achieve occupational exposures that were ALARA. The inspectors verified that PSEG had reasonably grouped the radiological work into work activities, based on historical precedence, industry norms, and/or special circumstances.

The inspectors compared the results achieved (dose rate reductions, person-rem used)with the intended dose established in PSEGs ALARA planning for these work activities.

The inspectors also reviewed the reason for any inconsistencies between intended and actual work activity doses.

Based on scheduled work activities and associated exposure estimates, the inspectors selected three work activities in radiation areas, airborne radioactivity areas, or high radiation areas for observation. The inspectors concentrated on work activities that presented the greatest radiological risk to workers. The inspectors evaluated PSEGs use of ALARA controls for these work activities by evaluating PSEGs use of engineering controls to achieve dose reductions.

The inspectors evaluated PSEG performance against the requirements contained in 10 CFR 20.1101.

b. Findings

No findings of significance were identified.

2OS3 Radiation Monitoring Instrumentation and Protective Equipment (71121.03 - 1 sample)

a. Inspection Scope

The inspectors identified the types of portable radiation detection instrumentation used for job coverage for high radiation area work, other temporary area radiation monitors currently used in the plant, and continuous air monitors associated with jobs with the potential for workers to receive 50 mrem committed effective dose equivalent.

The inspectors evaluated PSEG performance in this area against the requirements contained in 10 CFR 20.1501, 10 CFR 20.1703 and 10 CFR 20.1704.

b. Findings

No findings of significance were identified.

4OA1 Performance Indicator (PI) Verification

a. Inspection Scope

The inspectors reviewed PSEG submittals for the Unit 1 and Unit 2 initiating events cornerstone performance indicators discussed 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 Nuclear Energy Institute (NEI) 99-02, Regulatory Assessment Indicator Guideline, Revision 5.

Cornerstone: Initiating Events

• Unit 1 and Unit 2 unplanned scrams

• Unit 1 and Unit 2 unplanned scrams with complications

• Unit 1 and Unit 2 unplanned power changes

b. Findings

No findings of significance were identified.

4OA2 Identification and Resolution of Problems

.1 Review of Items Entered into the Corrective Action Program (CAP):

As required by Inspection Procedure 71152, Identification and Resolution of Problems, and in order to help identify repetitive equipment failures or specific human performance issues for follow-up, the inspectors performed a daily screening of all items entered into PSEG's corrective action program. This was accomplished by reviewing the description of each new notification and attending daily management review committee meetings.

Documents reviewed are listed in the Attachment.

b. Assessment and Observations No findings of significance were identified.

.2 Semi-Annual Review to Identify Trends

a. Inspection Scope

As required by Inspection Procedure 71152, AIdentification and Resolution of Problems,@

the inspectors performed a review of PSEG=s CAP and associated documents to identify trends that could indicate the existence of a more significant safety issue. The inspectors= review was focused on repetitive equipment and corrective maintenance issues, but also considered the results of daily inspector CAP item screening discussed in Section 4OA2.1. The review included issues documented in system health reports, corrective maintenance WOs, component status reports, site monthly meeting reports and maintenance rule assessments. The inspectors= review nominally considered the six-month period of December 1, 2007, through May 31, 2008, although some examples expanded beyond those dates when the scope of the trend warranted. The inspectors compared and contrasted their results with the results contained in PSEG=s latest integrated quarterly assessment report. Corrective actions associated with a sample of the issues identified in PSEG=s trend report were reviewed for adequacy. Documents reviewed are listed in the Attachment.

b. Assessment and Observations No findings of significance were identified. The inspectors noted a trend of low level issues entered into the CAP related to equipment reliability issues. Several unplanned equipment outages were required to make repairs to safety-related chillers, containment fan coil units, and service water pump strainers. In addition, the 13A circulating water screen was unreliable during the river grassing season this spring. The inspectors determined PSEG is aware of these areas identified through this trend review and is appropriately addressing these issues.

.3 Annual Sample: Human Performance, Procedure Use and Adherence

a. Inspection Scope

The inspectors reviewed the actions PSEG had taken to improve procedure use and adherence at the station. This sample evaluated PSEGs scope of efforts and progress in the area of procedure compliance for the period of January 2008 through June 2008.

b. Findings and Observations

No findings of significance were identified.

On August 31, 2007, the NRC identified a substantive cross-cutting issue in the area of human performance with a cross-cutting theme in the aspect of procedure compliance.

This substantive cross-cutting issue was maintained in the end of cycle assessment letter because PSEG did not meet the criteria for clearing the substantive cross-cutting issue. The root cause evaluation was completed by PSEG in December 2007, and some of the corrective actions were still in progress at the end of the assessment period.

The cause evaluation confirmed that personnel did not consistently meet management procedure use and adherence expectations. PSEG determined that the root cause was inadequate reinforcement and oversight of procedure use and adherence expectations.

As a result of inadequate reinforcement and oversight, the organization tolerated substandard procedures and a disregard for procedural steps perceived to be of low value.

The six month period following the completion of the root cause evaluation, January 2008 through June 2008, included approximately two months of outage preparation and two months of outage execution for steam generator replacement on Unit 2. A review of procedure compliance during the outage preparation period revealed only minor issues.

These issues were documented in PSEGs corrective action process or the PSEG fundamentals management system (FMS). Procedure compliance during the refuel outage and steam generator replacement on Unit 2 was also satisfactory. A large volume of clearance activities, maintenance activities, and testing activities were performed with only minor issues being noted.

During the week of June 16, 2008, PSEG conducted a self-assessment on procedure use and adherence. The self-assessment concluded that workforce behavior related to procedure use and adherence has improved and is in compliance with the standard, HU-AA-104-101, Procedure Use and Adherence. Several areas were observed and evaluated to make this determination. Results from 13 of 14 field observations were that the work force is adhering to procedures and work instructions, using place keeping, stopping when encountering ambiguity, and engaging supervisors in resolving issues.

Interviews with about 40 maintenance workers, security officers, engineers, operators, chemists, and RP technicians confirmed that procedure use and adherence standards are well known and reinforced by station management personnel. FMS and manager in the field reports reviewed indicated that procedure use and adherence is receiving priority attention from supervisors, superintendents, and managers in the field.

Inspectors independently checked for procedure compliance issues while work is in progress, and found that written procedures are being followed as technicians perform plant operations and maintenance. Technicians performing work were willing to discuss their compliance with procedures, and notifications were written to document changes requested to procedures to improve procedure quality.

Dynamic learning activities in procedure use and adherence were completed by maintenance, engineering, and operations departments. Chemistry had led the effort and completed their dynamic learning activity (DLA) training in 2007. These activities were one to four hours in duration, and were completed by each person prior to June 30, 2008. The DLAs are training exercises, where each technician is trained and provided feedback. In addition, maintenance has scheduled an out of the box evaluation for each technician during the third quarter of 2008. These evaluations will continue to reinforce the expectations for procedure use at the job site. All corrective actions from the root cause evaluation have been completed.

One area of the self-assessment that did not meet expectations was in the area of procedure quality. Procedure revision backlogs have not been reduced to target numbers, and a recovery plan is included in the self-assessment. Reduction of this backlog to reach year end goals is important to the stations continued improvement in procedure use and adherence.

4OA3 Event Followup

.1 Unit 2 Manual Reactor Trip

a. Inspection Scope

The inspectors responded to a manual reactor trip that occurred on May 9, 2008. As reactor power was being reduced in response to a partial loss of circulating water, the level in 23 steam generator approached the hi-hi level setpoint. Plant operators manually tripped the reactor due to the high steam generator level. The inspectors observed control room operators establish and maintain stable hot-standby conditions.

The inspectors walked down all control board indications for abnormalities, and interviewed operators for additional insights on equipment performance.

The inspectors discussed the reactor trip with PSEGs investigation team, managers, and engineers. The inspectors reviewed the initial investigation report and post-reactor trip report, and observed the plant operations review committee meeting on restart issues.

PSEGs initial investigation determined that the partial loss of circulating water was caused by a loss of power to the Unit 2 circulating water traveling screens. As debris built up on the traveling screens, differential level increased over time to reach the circulating water pump trip set point. The main turbine was tripped in accordance with the circulating water abnormal operating procedure, and the level controller for the 23 steam generator sensed an error that caused the controller to switch to manual. Steam generator level increased, and the plant operator tripped the reactor. Corrective actions resulting from this event were to repair the faulted electrical circuit powering the circulating water screens, and adjust the error sensing zero signal for the Unit 2 steam generators.

b. Findings

No findings of significance were identified.

.2 Unit 2 Forced Shutdown

a. Inspection Scope

The inspectors responded to a reactor shutdown that occurred on May 12, 2008. During power ascension following a refuel outage and steam generator replacement, plant operators identified a significant mismatch between feed flow indication and steam flow indication for each of the four steam generators. PSEG determined that the steam flow indication and input to reactor protection was calibrated improperly, and declared all eight steam flow protection circuits inoperable. The reactor was shut down in accordance with TS 3.0.3. The inspectors observed control room operators establish and maintain stable hot standby conditions.

The inspectors discussed the miscalibration and plant shutdown with PSEGs investigation team, managers, and engineers. The inspectors reviewed the initial investigation report, and observed the plant operations review committee on restart issues.

PSEGs initial investigation determined that the steam flow calibration errors were due to multiple errors with the data entered into the plant computer scaling model. These errors were corrected prior to plant restart, and steam flow indication was carefully monitored during plant power ascension.

b. Findings

No findings of significance were identified.

4OA5 Other Activities

.1 Steam Generator Replacement Inspection Procedure 50001

a. Inspection Scope

The inspectors verified that engineering evaluations and design changes associated with steam generator replacement (SGR) were completed in conformance with requirements in the facility license, the applicable codes and standards, licensing commitments, and the regulations.

The inspectors reviewed the applicable Design Change Packages (DCPs) that controlled the replacement of the steam generators. All DCPs were reviewed in accordance with the requirements of IP 71111.02, Evaluation of Changes, Tests and Experiments and IP 71111.17B, Permanent Plant Modifications.

The inspectors reviewed the administrative procedures that were used to control the screening, preparation, and issuance of the associated safety evaluations to ensure that the procedure adequately covered the requirements of regulation 10 CFR 50.59.

The inspectors reviewed the DCPs and implementing Work Packages for the site haul path for movement of the replacement steam generators (RSGs) and the old steam generators (OSGs). The review included the engineering evaluation of potentially affected underground piping systems, structures and electrical conduits for the operating unit (Unit 1) and for the necessary support equipment for the shutdown operation of Unit

2. The inspectors also reviewed the rigging and handling procedures for the OSGs and

the RSGs both inside and outside of containment. Access to containment for this replacement project was through the equipment hatch. No modification to the permanent containment structure was necessary for the steam generator replacement.

The inspectors performed a review of applicable procedures, work practices, and documentation of the steam generator replacement project (SGRP) to assess the control of safety related aspects associated with the major phases of the SG replacement. This inspection was focused on SGRP activities that restore the pressure boundary of the reactor coolant system (RCS), secondary systems, and affected containment systems, exclusion of foreign materials and plant modifications that could affect plant risk during the replacement activities or subsequent plant operation. The inspectors also examined the affected steam generator supports and affected piping system supports.

The inspectors performed a review of those procedures that governed field activities involving the cutting and machining of weld preparations at existing main steam (MS),feedwater (FW) and reactor coolant system (RCS) connections on the old steam generators (OSG). The inspectors examined welding procedures, welder qualifications, weld filler metal selection, non-destructive test procedures, examiner qualifications, acceptance criteria and test results for compliance with the requirements of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code (Code), Sections IX and XI. The inspectors examined training and qualification records for selected personnel performing welding and non-destructive examination. The inspectors selected a sample of Work Packages (WP) for review. The selection of these field planning and work documents was based on their risk significance and represented the installation by welding of FW, MS and RCS piping, fittings and pipe supports. The tracking and processing of the work planning and control documents was examined.

The work control documents selected were found to be appropriate for the work tasks specified and contained provisions and hold points to monitor weld progress, provide necessary in-process NDE and to close out the activities at the completion of work.

The inspectors reviewed the manufacturing records and primary and secondary shop fabrication hydrostatic testing records. The inspectors reviewed the non-destructive test results of the pre-service examinations of the RSG shell, nozzle and attachment welds and the baseline examination of the steam generator tubes. The inspectors also reviewed the SG degradation assessment developed in advance of the pre-service tube inspections (PSI) to be performed with respect to the limited range of degradation mechanisms that may pertain to the as-built condition.

Prior to beginning replacement activities the inspectors reviewed the rigging, lifting and handling procedures used to move the old steam generators from containment and move the new steam generators into place inside containment. The inspectors verified that PSEG addressed the potential impact on system and equipment from Unit 1, the operating unit, and had analyzed and addressed the potential for damage to existing plant SSCs due to the moving of these heavy loads. The inspectors directly observed the lifting, rigging and removal of the OSGs No. 22 and No. 24 out of containment The inspectors verified that PSEG provided temporary power to construction efforts inside the Unit 2 containment and that these power sources were independent from the operating Unit 1 and Unit 2 shutdown safety significant electrical loads.

The inspectors also reviewed the security considerations associated with vital and protected area barriers that may have been affected by the steam generator replacement activities. The inspectors also conducted a walkdown and review of security boundaries affected by the steam generator replacement project and conducted a review of PSEGs compensatory measures.

Specific work activities inspected included observation of the qualification of welders using the automated process for the welding of the RCS piping, MS piping and FW piping. Also, the inspectors observed the machining of weld preparations on selected samples of MS, FW and RCS piping spools and assessed the dimensional accuracy for comparison with specification requirements. The inspectors reviewed SGT work package No. 3065C, RCS Machining and Welding SG-23, and discussed the RCS hot and cold leg piping end preparation machining tasks with the machinist performing the activity. The inspectors observed the shop welding of various piping spools in the pipe fabrication shop prior to their movement to the field for installation. The inspectors observed the field fit-up, tack welding and final welding of a sample of these components to their respective steam generator nozzles.

One field weld from each of the MS, FW and RCS piping was selected by the inspectors for an in depth review of fabrication work documentation, including the severance at the steam generator nozzle to the completion of re-attachment to the steam generator including in process and final non-destructive testing of the new welds. The final non-destructive tests for the acceptance of these risk significant welds involved surface and radiographic testing. Also, ultrasonic testing was required for each weld to establish baseline quality levels for comparison during subsequent ASME Section XI exams (in-service inspection). The inspectors reviewed the test activities and inspection reports to assess the completeness of the examination processes. Also, the inspectors conducted interviews with design and field engineers, and with construction and examination personnel responsible for implementing these activities.

The inspectors reviewed the post-steam generator replacement NDE of all new welds for the risk significant RCS, MS and FW systems. The inspectors also reviewed the in-service ultrasonic inspection baseline examinations performed on the new RCS, MS and FW system piping welds.

The inspectors reviewed the SG post-installation test program and PSEG documentation for the RCS system pressurization leak test and walkdown during initial plant startup.

The inspectors also reviewed the testing documentation used to verify that RCS flow for the new steam generators conformed to design predictions and a sample of calibration and testing procedure results for plant instrumentation affected by the steam generator replacement.

The inspectors reviewed the planned startup testing procedure for the replacement steam generators. The testing procedure was part of the OSG replacement project plan and was evaluated as part of the steam generator replacement 10 CFR 50.59 evaluation.

The inspectors reviewed the following radiation protection program controls, planning, and preparation, against the requirements contained in 10 CFR 20, 10 CFR 20.1101, and Unit 2 Technical Specification 6.12.:

• ALARA planning. The inspectors reviewed ALARA planning documents, including ALARA plans and micro-ALARA plans written in support of the steam generator replacement project, and also examined in-progress work reviews. Eleven ALARA plans and one micro-ALARA plan were written in support of the project. The inspectors verified that the ALARA planning process took into account both individual and collective dose considerations.

The inspectors reviewed the ALARA work activity evaluations, exposure estimates, and exposure mitigation requirements. The inspectors determined that PSEG had established procedures, engineering and work controls, based on sound radiation protection principles, to achieve occupational exposures that were ALARA. The inspectors determined that PSEG had reasonably grouped the radiological work into work activities, based on historical precedence, industry norms, and/or special circumstances.

• Dose estimates and dose tracking. The inspectors reviewed pre-outage estimates and goals, together with in-progress dose tracking data. The inspectors verified that daily dose tracking data was provided to management, and that individual and work group data was also readily available.

The inspectors compared the results achieved (dose rate reductions, person-rem used) with the intended dose established in the licensees ALARA planning for these work activities. The inspectors determined the causes for any inconsistencies between intended and actual work activity doses. Total dose for the steam generator replacement project was 15 person-rem below the pre-outage estimate.

• Exposure controls including temporary shielding. The inspectors verified that the ALARA plans included the use of temporary shielding and other engineering controls to minimize exposure. The inspectors conducted numerous in-field observations to verify that shielding packages were installed as described, and that engineering controls were being appropriately utilized.

• Contamination controls. The inspectors conducted numerous observations of contamination controls implemented in the radiologically controlled area, especially in the containment building. The inspectors verified that contamination controls were appropriately implemented, that barriers were appropriately installed and that sufficient radiological postings were available to inform the workers.

During job performance observations, the inspectors observed radiation worker performance with respect to stated radiation protection work requirements. The inspectors determined if they were aware of the significant radiological conditions in their workplace, and the radiation work permit controls/limits in place, and that their performance took into consideration the level of radiological hazards present.

• Radiological material management. The inspectors verified that materials removed from the old steam generators and other contaminated materials were being appropriately identified, segregated and processed. The inspectors made their determination via direct observations and review of PSEG documents.

• Radiological work plans and controls. The inspectors reviewed PSEG procedures, radiation work permits and ALARA plans related to the steam generator replacement.

The inspectors conducted direct observations of PSEG work in progress to verify that the plans and controls described were being appropriately implemented.

The inspectors observed work that was estimated to result in the highest collective doses, involved diving activities in or around spent fuel or highly activated material, or that involved potentially changing (deteriorating) radiological conditions. The inspectors reviewed the radiological job requirements (radiation work permit requirements and work procedure requirements). The inspectors observed job performance with respect to these requirements. The inspectors determined if radiological conditions in the work area were adequately communicated to workers through briefings and postings.

During job performance observations, the inspectors verified the adequacy of radiological controls, such as: required surveys (including system breach radiation, contamination, and airborne surveys), radiation protection job coverage (including audio and visual surveillance for remote job coverage), and contamination controls.

The inspectors reviewed radiation work permits used to access these and other high radiation areas and identify what work control instructions or control barriers had been specified. The inspectors used plant-specific technical specification high radiation area requirements as the standard for the necessary barriers. The inspectors reviewed electronic personal dosimeter alarm set points (both integrated dose and dose rate) for conformity with survey indications and plant policy. The inspectors verified that workers know what actions are required when their electronic personal dosimeter noticeably malfunctions or alarms.

• Emergency contingencies. The inspectors reviewed ALARA plans and radiation work permits utilized for the steam generator replacement, and verified that back-out dose rates and other radiological limits were identified and communicated to the workers.

The inspectors did not identify any instances were radiological limits were exceeded.

• Project staffing and training plans. The inspectors reviewed PSEGs radiation protection staffing plan, and verified that adequate radiation protection technicians and other radiological staff were available on both day and night shifts.

During job performance observations, the inspectors observed radiation protection technician performance with respect to all radiation protection work requirements.

The inspectors determined if they were aware of the radiological conditions in their workplace and the radiation work permit controls/limits, and if their performance was consistent with their training and qualifications with respect to the radiological hazards and work activities.

• Radiological safety plans for storage of retired steam generators and components.

The inspectors reviewed PSEGs plan for temporary storage of the old steam generators at the interim low level radioactive waste storage facility. The inspectors toured the storage location, and verified that dose rate limits set forth in PSEGs plan were not being exceeded. The inspectors reviewed PSEGs transport and disposal plan for the OSGs, scheduled to take place in late 2008.

b. Findings

During the sixteenth refueling outage at Unit 2, all four steam generators and the high pressure turbine were replaced. These replacements resulted in changes to various plant parameters, including main steam flow rate and pressure. PSEG developed post modification acceptance test procedure S2.PI-SP.ZZ-0001, Power Ascension Test for HP Turbine and Steam Generator Replacement, to support this work. The purpose of power ascension testing was to validate predicted values for reactor coolant flow rate, pressurizer water level, main steam flow rates and main steam inlet pressure to the high pressure turbine. Power ascension testing was to be initiated at 18% reactor power and was to be performed in conjunction with normal plant startup procedures.

During startup power ascension testing was not implemented as planned and as a result operators did not recognize that all Unit 2 high steam flow protection channels were inoperable until the plant reached 84% power. Operators ultimately identified the condition because the steam flow rate measurement used for protection and indication was outside of acceptable limits, and entered TS 3.0.3 and conducted a plant shutdown.

PSEG completed troubleshooting and determined that a number of engineering deficiencies and incomplete post modification test plan implementation ultimately resulted in the inoperable high steam flow protection channels. This issue is unresolved pending PSEGs completion of its root cause evaluation, inspector review of the root cause evaluation and additional inspector review of design control practices associated with the steam generator replacement project. (URI 05000311/2008003-04, Salem Unit 2 Steam Flow - Feed Flow Mismatch)

.2 (Closed) Temporary Instruction 2515/166 - Pressurized Water Reactor Containment

Sump Blockage (NRC Generic Letter 2004-02)

a. Inspection Scope

The inspectors performed an inspection in accordance with Temporary Instruction (TI)2515/166, Pressurized Water Reactor Containment Sump Blockage, Revision 1. The TI was developed to support the NRC review of licensee activities in response to NRC Generic Letter (GL) 2004-02, Potential Impact of Debris Blockage on Emergency Sump Recirculation at Pressurized Water Reactors. Specifically, the inspectors verified that the implementation of the modifications and procedure changes were consistent with the actions discussed in PSEGs letters to the NRC, dated December 10, 2007 and February 29, 2008. The February 29, 2008 letter to the NRC included PSEGs response to the draft open items from the NRR audit of corrective actions to address Generic Letter 2004-02, conducted in October 2007.

The inspectors reviewed the technical specifications (TS) and the Updated Final Safety Analysis Report (UFSAR) to verify that required changes to the TS had been approved by the NRC, and that the UFSAR had been or was in the process of being updated to reflect the plant changes. Additionally, the inspectors reviewed a sample of procedures to verify that they were updated to reflect programmatic changes to the facility. The inspectors also reviewed a sample of work orders to verify that specific work had been performed to meet PSEGs GL commitments. Finally, the inspectors discussed details of the containment sump modification with engineers to verify design control of the modification process. Documents reviewed are listed in the attachment. Portions of the TI were performed during the 2006 refueling outage at Unit 2, and the 2007 refueling outage at Unit 1, to verify the physical modifications to the containment sump. The results of those inspections were documented in Inspection Report Nos.

05000311/2006005 and 05000272/2007003.

b. Evaluation of Inspection Requirements The TI requires the inspectors to evaluate and answer the following questions:

Did the licensee implement the plant modifications and procedure changes committed to in their GL 2004-02 response?

The inspectors verified that PSEG has implemented, or was in the process of implementing, the plant modifications and procedure changes committed to in their GL 2004-02 responses. The inspections previously performed in 2006 and 2007 verified the implementation of the sump screen modifications as related to the GL.

During this inspection, the inspectors verified that procedures were updated as related to programmatic controls of potential debris sources, and inspections for containment coating degradation. Additionally, the inspectors verified that evaluations to address downstream effects had been performed on both units.

At the time of inspection, inspectors noted that PSEG was still performing chemical effects testing on both units.

2. Has the licensee updated its licensing basis to reflect the corrective actions taken in response to GL 2004-02?

The inspectors verified that changes to the facility or procedures, as described in the Updated Final Safety Analysis Report (UFSAR), and identified in PSEGs GL 2004-02 responses, were reviewed and documented in accordance with 10 CFR 50.59. The inspectors also verified that PSEG had obtained NRC approval prior to implementing those changes that required such approval. Specifically, PSEG had obtained NRC approval prior to implementing changes to the methodology for NPSH calculations for the Emergency Core Cooling System (ECCS) pumps. Finally, the inspectors verified that PSEG had either updated, or was in the process of updating, the UFSAR to reflect the required changes in response to GL 2004-02.

Based on the inspectors review of the hardware modifications, procedure changes, and licensing bases changes, the inspection requirements of the Temporary Instruction are complete and the TI is closed at Salem Units 1 and 2. In a letter to the NRC dated June 26, 2008, as supplemented by letter dated July 10, 2008, PSEG requested an extension for completion of certain corrective actions required under Generic Letter 2004-02. As of this inspection, the remaining activities include completion of strainer performance and chemical bench top testing, and incorporation of the test results into the ECCS NPSH calculations for both units. In a letter dated July 31, 2008, NRR approved PSEGs request to extend the completion date for the remaining testing and analyses required for GL 2004-02 compliance until December 31, 2008. In addition, PSEG has to provide an updated GL 2004-02 supplemental response within 90 days of completing the remaining activities, but not later than March 31, 2009.

The TI-2515/166 inspection results, as well as any results of sampling audits of licensee actions will be reviewed by the NRC staff (Office of Nuclear Reactor Regulation-NRR) as input, along with the Generic Letter 2004-02 responses to support closure of GL 2004-02 and Generic Safety Issue (GSI)-191, Assessment of Debris Accumulation on Pressurized-Water Reactor (PWR) Sump Performance. The NRC will notify PSEG by letter of the results of the overall assessment as to whether GSI-191 and GL 2004-02 have been satisfactorily addressed at Salem Generating Station. Completion of TI-2515/166 does not necessarily indicate that PSEG has finished all testing and analyses needed to demonstrate the adequacy of their modifications and procedure changes. As noted above, PSEG has obtained approval of a plant-specific extension that allows for completion of testing and analyses, as well as any necessary updates to calculations.

PSEG will confirm completion of all corrective actions to the NRC. As part of the process described above to ensure satisfactory resolution of GL 2004-02 and GSI-191, the NRC will track all such yet-to-be-performed items identified in the TI-2515/166 inspection reports, track the items to completion, and may choose to inspect implementation of some or all of them.

c. Findings

No findings of significance were identified.

4OA6 Meetings, Including Exit

On July 9, 2008, the resident inspectors presented the inspection results to Mr. Braun.

PSEG acknowledged that none of the information reviewed by the inspectors was proprietary.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee personnel

D. Best, System Engineer - Electrical

R. Chan, Salem Maintenance Superintendant - I&C

V. Ciarlante, Manager Electrical/I&C Design

J. FitzPatrick, Nuclear Technical Supervisor

R. Gary, Radiation Protection Manager

G. Gaydos, Manager Steam Generator Project

J. Giunta, System Engineer - Electrical

L. Gonzalez, Design Engineer - Electrical/I&C

G. Greer, System Engineer - Electrical

R. Halter, Manager Outages

D. Hayman, Salem Maintenance Superintendant - I&C

R. Henriksen, Plant Engineering Manager - Balance of Plant

S. Milligan, I&C Maintenance Supervisor

T. Neufang, Nuclear Technical Supervisor

T. Nolte, Design Engineer - Mechanical/Structural

L. Rajkowski, Manager Design Engineering - Salem

B. Settle, Manager Engineering Response

J. Starceivich, Work Management Cycle Planner

S. Zieglar, Work Week Specialist

E. Villar, Licensing Engineer

K. Mathur, Mechanical Design Engineering

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

05000311/2008003-04 URI Salem Unit 2 Steam Flow Feed Flow Mismatch (Section 4OA5)

Opened/Closed

05000311/2008003-01 NCV Salem Unit 2 Loss of All Three Chillers (Section 1R13)

05000311/2008003-02 NCV Salem Unit 2 Loss of Reactor Vessel Level Indication System (Section 1R15)

05000311/2008003-03 NCV Salem Unit 2 22 CFCU Valves Mispositioned (Section 1R22)

05000272,311/2515/166 TI Pressurized Water Reactor Containment Sump Blockage (Section 40A5)