IR 05000272/2006003

IR 05000272-06-003, 05000311-06-003; 04/01/2006 - 06/30/2006; Salem Nuclear Generating Station Units 1 and 2; Routine Integrated Report

ML062000418
Person / Time
Site:	Salem
Issue date:	07/19/2006
From:	Gray M K Reactor Projects Branch 3
To:	Levis W Public Service Enterprise Group
Welling B D, RGN-I/DRP/PB3, 610-337-5328
References
IR-06-003
Download: ML062000418 (34)

Text

July 19, 2006

Mr. William LevisSenior Vice President and Chief Nuclear Officer PSEG LLC - N09

P. O. Box 236 Hancocks Bridge, NJ 08038

SUBJECT: SALEM NUCLEAR GENERATING STATION - NRC INTEGRATEDINSPECTION REPORT 05000272/2006003 and 05000311/2006003

Dear Mr. Levis:

On June 30, 2006, the US Nuclear Regulatory Commission (NRC) completed an inspection atthe Salem Nuclear Generating Station. The enclosed integrated inspection report documentsthe inspection findings, which were discussed on July 6, 2006, with Mr. T. Joyce and other members of your staff.The inspection examined activities conducted under your license as they relate to safety andcompliance with the Commission's rules and regulations and with the conditions of your license.

The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel. Based on the results of this inspection, no findings of significance were identified.

In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter and itsenclosure will be available electronically for public inspection in the NRC Public DocumentRoom 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/Mel Gray, Chief Projects Branch 3 Division of Reactor ProjectsDocket Nos:50-272; 50-311License Nos:DPR-70; DPR-75 Mr. W. Levis2 2

Enclosure:

Inspection Report 05000272/2006003 and 05000311/2006003

w/Attachment:

Supplemental Informationcc w/encl:T. Joyce, Site Vice President - Salem D. Winchester, Vice President Nuclear Assessments W. F. Sperry, Director Business Support D. Benyak, Director - Regulatory Assurance C. J. Fricker, Salem Plant Manager J. J. Keenan, Esquire M. Wetterhahn, Esquire F. Pompper, Chief of Police and Emergency Management Coordinator P. Baldauf, Assistant Director, Radiation Protection and Release Prevention, State of New Jersey K. Tosch, Chief, Bureau of Nuclear Engineering, NJ Dept. of Environmental Protection H. Otto, Ph.D., DNREC Division of Water Resources, State of Delaware Consumer Advocate, Office of Consumer Advocate N. Cohen, Coordinator - Unplug Salem Campaign W. Costanzo, Technical Advisor - Jersey Shore Nuclear Watch E. Zobian, Coordinator - Jersey Shore Anti Nuclear Alliance M

SUMMARY OF FINDINGS

IR 05000272/2006003, 05000311/2006003; 04/01/2006 - 06/30/2006; Salem NuclearGenerating Station Units 1 and 2; routine integrated report. The report covered a 13-week period of inspection by resident inspectors, and announcedinspections by a regional radiation specialist, a regional projects inspector, reactor inspectors and operations engineers. The NRC's program for overseeing the safe operation ofcommercial nuclear power reactors is described in NUREG-1649, "Reactor Oversight Process,"Revision 3, dated July 2000.A.

NRC-Identified and Self-Revealing Findings

No findings of significance were identified.

B.Licensee Identified Violations

None.

REPORT DETAILS

Summary of Plant StatusUnit 1 began the period at 100 percent (%) power and remained at or near 100% for the entirequarter.Unit 2 began the period at 100% power. Unit 2 was reduced to 75% reactor power on May 6,2006, for planned maintenance on the main turbine governor control valves. Unit 2 returned to 100% power on the same day and remained at or near 100% for the remainder of the quarter.1.REACTOR SAFETYCornerstones: Initiating Events, Mitigating Systems and Barrier Integrity1R01Adverse Weather Protection (71111.01)

a. Inspection Scope

(1 sample)The inspectors reviewed PSEG's completed procedure SC.OP-PT.ZZ-0002, "StationPreparations for Seasonal Conditions," for hot weather conditions. Inspectors reviewed Unit 1 and Unit 2 system health reports for the service water, component cooling, andauxiliary building ventilation systems, and interviewed responsible system engineers. The inspectors also reviewed operability determinations potentially impacted by hotweather and interviewed station personnel responsible for implementing severe weather preparations. Documents reviewed are listed in the attachment.

b. Findings

No findings of significance were identified.

1R04 Equipment Alignment (71111.04)

a. Inspection Scope

(3 samples)Partial Walkdowns. The inspectors performed partial walkdowns of three systems toverify the operability of redundant or diverse trains and components when safetyequipment was inoperable. The inspectors focused their review on potential discrepancies that could impact the function of the system, and therefore, potentiallyincrease risk. The inspectors reviewed applicable operating procedures, walked down control systems components, and verified that selected breakers, valves, and supportequipment were in the correct position to support system operation. The inspectors alsoverified that PSEG had properly identified and resolved equipment alignment problemsthat could cause initiating events or impact the capability of mitigating systems orbarriers and entered them into the corrective action program. Documents reviewed are listed in the attachment. The following three systems were walked down:

2Enclosure Unit 2 component cooling (CC) system during the 22 CC heat exchanger outage;Unit 2 boration flow paths during maintenance to the 22 boric acid tank; andUnit 2 chemical and volume control system during and after maintenance to the22 charging pump discharge check valve (2CV52).

b. Findings

No findings of significance were identified.

1R05 Fire Protection (71111.05)

a. Inspection Scope

(6 samples)Fire Protection - Tours. The inspectors walked down six areas to assess the materialcondition and operational status of fire protection features. The inspectors verified that combustibles and ignition sources were controlled in accordance with PSEG's administrative procedures; fire detection and suppression equipment was available for use; that passive fire barriers were maintained in good material condition; and that compensatory measures for out-of-service, degraded, or inoperable fire protection equipment were implemented in accordance with PSEG's fire plan. Documents reviewed are listed in the attachment. The following fire areas were inspected:Unit 1 and Unit 2 emergency diesel generator fuel oil storage area;Unit 1 and Unit 2 spent fuel, safety injection, and component cooling pump area; andUnit 1 and Unit 2 230Vac and 460Vac vital switchgear rooms and corridor.

b. Findings

No findings of significance were identified.

1R06 Flood Protection Measures (71111.06)

a. Inspection Scope

(1 sample)Internal Flooding Review. The inspectors evaluated internal flood protection measuresfor the 460/230Vac vital switchgear and relay rooms for both Salem Units. The areas were walked down to assess operational readiness of various features to protect vital electric power systems from internal flooding. These features included plant drains,flood barrier curbs, and wall penetration seals. The inspectors also reviewed the results of the most recent flood barrier penetration seal inspection and notifications associated with flood protection measures. Finally, the inspectors interviewed main control room operators regarding their knowledge of indications, procedures and required actions during a postulated non-seismic fire protection piping rupture. Documents reviewed are listed in the attachment.

b. Findings

3Enclosure No findings of significance were identified.

1R07 Heat Sink Performance (71111.07)

a. Inspection Scope

Resident Inspector Annual Review (1 sample). The inspectors reviewed performancedata and interviewed the program manager responsible for implementation of NRC Generic Letter 89-13 to verify that potential heat exchanger or heat sink deficiencieswere identified and that PSEG adequately resolved heat sink performance problems. Specifically, the inspectors reviewed the 15 service water pump upper motor bearing heat exchanger performance data. Inspectors evaluated trending data and verified equipment would perform satisfactorily under design basis conditions. The method of performance monitoring was compared against NRC Generic Letter 89-13, "ServiceWater System Problems Affecting Safety-Related Equipment," and EPRI NP-7552, "Heat Exchanger Performance Monitoring Guidelines," for conformance to these guidance documents. Additional documents reviewed are listed in the attachment.Biennial Review by Regional Staff (3 samples). Based on plant specific risk importanceand resident inspector input, the inspectors selected the 21 charging pump gear oil cooler, the 11 auxiliary feedwater pump room cooler, and the 2C emergency dieselgenerator (EDG) lube oil cooler as samples for this inspection.For the selected components, the inspectors reviewed the testing and cleaning methodsused by PSEG to ensure heat removal capabilities were consistent with commitmentsmade in response to Generic Letter 89-13, "Service Water System Problems Affecting Safety-Related Equipment," and accepted industry practices. The inspectors determined that the procedure used to quantify macrofouling of the charging pumpcoolers was adequate and in accordance with accepted industry practices. The inspectors also reviewed methods for monitoring and controlling biotic and macro-fouling and verified their effectiveness.The inspectors walked down the selected components and the service water intake structure to assess the general material condition of the selected heat exchangers and associated service water components. The inspectors also inspected the internal components of the 22 service water pump strainer, which was open for corrective maintenance, and observed the type and quantity of material present within the strainer. The inspectors reviewed a sample of notifications related to the selected heat exchangers to ensure that problems related to these components were appropriately identified, characterized, and corrected. Documents reviewed are listed in the attachment.

b. Findings

No findings of significance were identified.

4Enclosure

1R11 Licensed Operator Requalification Program

a. Inspection Scope

(1 sample)Resident Inspector Quarterly Review. The inspectors observed a simulator trainingscenario conducted on May 30, 2006, to assess operator performance and training effectiveness. The scenario involved a 2B emergency diesel generator malfunction, a 21 hydrogen analyzer instrument failure, total loss of component cooling water, and a total loss of all ac electrical power. The inspectors verified operator actions were consistent with operating, alarm response, abnormal, and emergency procedures. The inspectors assessed simulator fidelity and verified that evaluators identified deficient operator performance where appropriate. The inspectors observed the simulator instructors' critique of operator performance. Documents reviewed are listed in the attachment.

b. Findings

No findings of significance were identified.

1R12 Maintenance Effectiveness (71111.12)

a. Inspection Scope

(2 samples)Resident Inspector Quarterly Review. The inspectors reviewed performance monitoringand maintenance effectiveness issues for a 15 service water pump motor upper bearing overheating condition and a 22 service water pump strainer motor overload trip. These issues were initially entered into PSEG's corrective action program as notifications 20275072 and 20275035, and both occurred on March 10, 2006. The inspectors assessed whether PSEG was adequately monitoring equipment performance to ensure that preventive maintenance was effective. The inspectors verified that the componentswere monitored in accordance with the maintenance rule program requirements. The inspectors compared documented functional failure determinations and unavailabilityhours to those being tracked by PSEG to evaluate the effectiveness of PSEG's condition monitoring activities and to determine whether performance goals were being met. The inspectors reviewed applicable work orders, corrective action notifications, and preventive maintenance tasks. The inspectors also interviewed pertinent systemengineers. Documents reviewed are listed in the attachment.

b. Findings

No findings of significance were identified. However, issues involving maintenanceeffectiveness for the 22 service water strainer (SWS) are unresolved pending further inspection of PSEG's evaluation of maintenance practices, engineering evaluation of the repeat 22 SWS trips, and testing of the thermal overload protective devices.On March 3, 2006, maintenance technicians completed preventive maintenance (Order30083454) on the 22 SWS. Between March 3 and March 10, 2006, the 22 SWS 5Enclosure operated for 114 hours0.00132 days <br />0.0317 hours <br />1.884921e-4 weeks <br />4.3377e-5 months <br />. On March 10, 2006, the 22 SWS tripped on the strainer motorthermal overload. Operators reset the thermal overload protective devices and testedthe 22 SWS by running it in manual. PSEG procedure SC.OP-DD.ZZ-0006, Protective Circuit/Breaker Reset and Reclosure Policy, Revision 0, permitted equipment operators to reset the overload devices one time without determining the cause of the trip. The 22 SWS was next started on March 11, 2006, and operated for approximately two hours before tripping again.PSEG entered this issue into the corrective action program (20275035) and completedcorrective maintenance (20275118). The corrective maintenance included increasing the internal drum-to-body clearances from approximately 0.020 inches to approximately 0.050 to 0.063 inches. The inspectors noted that PSEG did not evaluate the cause ofthe 22 SWS trip. Salem personnel later determined the 22 SWS tripped because internal drum-to-body clearances were too tight following the maintenance on March 3, 2006 (20280934).Subsequently, the inspectors reviewed the completed work package (30083454) andfound the internal drum-to-body clearances following the maintenance on March 3, 2006, may not have been too tight. Moreover, the drum-to-body clearances were adjusted during this preventive maintenance activity, but the portion of the procedure that directed clearance adjustment was marked not applicable. Finally, the drum-to-body clearances decreased while 22 SWS operated between March 3 and March 10, 2006.PSEG then evaluated the 22 SWS trip and concluded, consistent with inspectorobservations, the 22 SWS internal clearances decreased during operation (70057833).

PSEG identified two possible causes: the 22 SWS lower locknut may not have been tightened, or the 22 SWS lower locknut may not have been locked in place. Eithercause would have decreased the 22 SWS internal clearances by allowing the internal drum to drift deeper into the external body. Both locknut tightening and locknut locking were required by procedure SC.MD-PM.SW-0003, Service Water Auto Strainer Adjustment, Inspection, Repair and Replacement, Revision 25.Late in the inspection period, on June 27, 2006, the 22 SWS tripped twice on thermaloverload and was removed from service for troubleshooting and corrective maintenance (20289327, 20289407). The inspectors noted that the 22 SWS motor overload protective devices were not tested during this troubleshooting activity.The issue is unresolved pending inspector review of PSEG's evaluation of maintenancepractices, engineering reevaluation of the repeat 22 SWS trips and testing of the thermal overload protective devices. PSEG issued corrective action notification20289840 to reevaluate the 22 SWS trips. (URI 05000311/2006003-01, 22 ServiceWater Strainer Multiple Trips)6Enclosure

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

(6 samples)The inspectors reviewed six maintenance activities to verify that the appropriate riskassessments were performed as required 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 to verify that concurrent planned, and emergent maintenance and test activities did not adversely affect the plant risk already incurred with these configurations. PSEG's risk management actions were reviewed during shift turnover meetings, control room tours, and plant walkdowns. The inspectors also used PSEG's on-line risk monitor (Equipment Out Of Service Workstation) to evaluate the risk associated with the plant configuration and to assessPSEG's risk management. Documents reviewed are listed in the attachment. The following plant configurations were assessed:Unit 3 gas turbine generator and 1PR2 pressurizer power operated relief valvemaintenance;1C emergency diesel generator and 15 service water pump maintenance;22 component cooling pump maintenance;22 charging pump during repairs to discharge check valve, 2CV52;22 component cooling heat exchanger outage; and12 switchgear exhaust fan, 13 service water pump and 11 rod drive motorgenerator maintenance.

b. Findings

No findings of significance were identified.

1R15 Operability Evaluations (71111.15)

a. Inspection Scope

(5 samples)The inspectors reviewed five operability determinations for degraded or non-conformingconditions associated with:Notification 20284189, 22 service water strainer blowdown valve remained mid-position;Notification 20276469, 1C emergency diesel generator (EDG) over-crank trip onMarch 21, 2006;Condition report (NUCR) 70057799, operability determination (OD) for reliabilityof Salem Unit 1 and 2 EDGs with potentially degraded cylinder heads supplied by a vendor;Notifications 20237806 and 20272927 concerning potential centrifugal chargingpump run out during safety injection; andNotification 20276480 concerning operability of the 23 auxiliary feedwater pumproom ventilation with solenoid valve 2ABS2-SV1093 degraded.

7Enclosure The inspectors reviewed the technical adequacy of the operability determinations toensure that technical specification operability and technical conclusions were justified. Inspectors verified that no unrecognized increase in risk occurred due to the listed conditions. The inspectors also walked down accessible equipment to corroborate the adequacy of PSEG's operability determinations. Documents reviewed are listed in theattachment.

b. Findings

No findings of significance were identified.

1R19 Post-Maintenance Testing (71111.19)

a. Inspection Scope

(6 samples)The inspectors observed portions of and/or reviewed results of six post-maintenancetests for the following equipment:*Work order (WO) 60061092, 22 component cooling pump mechanical sealreplacements;*WO 60062984, 1C emergency diesel generator 5R cylinder head replacement;

• WO 60061996, 1C 125 VDC battery cell replacement;

• WO 60060740, on-line repair of 22 charging pump discharge check valve(2CV52);*WO 60060959, replacement of service water valve 13SW46; and

• WOs 30074181, 30074221, 30107211, 30124651, 30132800 and 30134087, 12service water pump preventive maintenance outage.The inspectors assessed whether:

(1) the effect of testing on the plant had beenadequately addressed by control room and engineering personnel;

(2) testing was adequate for the maintenance performed;

(3) acceptance criteria were clear and adequately demonstrated operational readiness, consistent with design and licensing basis documentation;

(4) test instrumentation had current calibration, range, andaccuracy for the application;

(5) tests were performed, as written, with applicable prerequisites satisfied; and

(6) equipment was returned to an operational status and ready to perform its safety function. Documents reviewed are listed in the attachment.

b. Findings

No findings of significance were identified.

8Enclosure

1R22 Surveillance Testing

a. Inspection Scope

(6 samples)The inspectors observed portions of and/or reviewed results for six surveillance tests toverify, as appropriate, whether the applicable system requirements for operability wereadequately incorporated into the procedures and that test acceptance criteria wereconsistent with procedure requirements, the technical specification requirements, theUpdated Final Safety Analysis Report (UFSAR), and ASME Section XI for pump and valve testing. Documents reviewed are listed in the attachment. The following surveillance tests were inspected:Work Order (WO) 50093126, SC.MD-ST.125-0003, Quarterly Inspection andPreventive Maintenance of Units 1, 2 & 3 125 Volt Station Batteries, Rev. 22, for the 1C 125Vdc safety-related battery;WOs 50083926, 50083906, 50090925, 50093004, and 50094225, 2B dieselgenerator monthly surveillance, cyclic endurance run and cyclic hot restart test;WOs 50094379 and 50093177, 1C diesel generator monthly surveillancepursuant to adverse condition monitoring plan 06-10;WOs 30102967, 40023364, and 50093561, S2.OP-ST.

RHR-0001, InserviceTesting - 21 Residual Heat Removal Pump, Rev. 20;WOs 50094702 and 50094702, S2.OP-ST.AF-0003, Inservice Testing - 23Auxiliary Feedwater Pump, Rev. 41; andWO 50094596, S1.OP-ST.CVC-0003, Inservice Testing - 11 Charging Pump,Rev. 17.

b. Findings

No findings of significance were identified.Cornerstone: Emergency Preparedness [EP]1EP6Drill Evaluation (71114.06)

a. Inspection Scope

(1 sample)The inspectors observed one EP drill from the control room simulator on J une 7, 2006. The inspectors evaluated drill performance relative to developing event classifications and implementation of notifications. The inspectors reviewed the Salem Event Classification Guides and Emergency Plans. The inspectors referenced Nuclear Energy Institute 99-02, Regulatory Assessment Performance Indicator (PI) Guideline, Revision 3, and verified that PSEG correctly counted this drill's contribution to the NRC PI for Drilland Exercise Performance. Additional documents reviewed are listed in the attachment.

b. Findings

No findings of significance were identified.

9Enclosure

RADIATION SAFETY

Cornerstone:

Occupational Radiation Safety [OS]2OS1Access Control to Radiologically Significant Areas (71121.01)

a. Inspection Scope

(6 samples)The inspectors reviewed PSEG's self-assessments, audits, licensee event reports, andspecial reports related to the access control program since the previous NRC inspectionand determined that identified problems were appropriately entered into the correctiveaction program for resolution.The inspectors reviewed notifications and corrective action evaluations related to accesscontrols. Included in this review were PSEG-identified high radiation area radiological incidents in high radiation areas <1R/hr. For repetitive deficiencies or significant individual deficiencies in problem identification and resolution, the inspectors verified that PSEG self-assessment activities were also identifying and addressing these deficiencies.The inspectors reviewed PSEG documentation packages for all NRC PerformanceIndicator (PI) events occurring since the last NRC inspection and determined if any ofthese PI events involved dose rates >25 R/hr at 30 centimeters or >500 R/hr at 1 meter.

The inspectors ascertained what barriers failed and if any barriers remained to prevent personnel access. For unintended exposures >100 mrem Total Effective Dose Equivalent, >5 rem Skin Dose Equivalent, or >1.5 rem Lens Dose Equivalent, the inspectors determined if overexposure or a substantial potential for overexposure also occurred. The inspectors reviewed radiological problem reports which included causal factorsrelated to radiation worker or radiation protection technician errors and assessed if adverse trends existed. Corrective actions completed or intended by PSEG were also reviewed. The inspectors verified adequate posting and locking of entrances, if reasonably accessible, to all high dose rate - high radiation area and very high radiation areas.The inspectors also reviewed PSEG surveys and walked down the areas identified byPSEG as having groundwater in-leakage containing small amounts of cesium-137 within Unit 1. These areas were the 4kV vital bus area, the mechanical penetration area, and the electrical penetration area. Each was determined by the inspectors to be appropriately posted and controlled for the radiological contamination identified.

b. Findings

No findings of significance were identified.

10Enclosure 2OS2ALARA Planning and Controls (71121.02)

a. Inspection Scope

(2 samples)The inspectors reviewed PSEG's self assessments, audits, and special reports relatedto the as low as is reasonably achievable (ALARA) program since the last NRC inspection. The inspectors verified PSEG's overall audit program's scope and frequency (for all applicable areas under the Occupational Cornerstone) satisfied the requirements of 10 CFR 20.1101.c.The inspectors reviewed dose significant post-job and post-outage ALARA reportcritiques and verified that identified problems were appropriately entered into the corrective action program. The inspectors assessed the description, priority and resolution of each issue.On May 8, 2006, the inspectors attended a station ALARA committee meeting. Theprincipal topic of the meeting reviewed the residual heat removal system area paintingproject, and alternative methods to minimize the dose for the project, which was estimated at 1.994 person-rem.

b. Findings

No findings of significance were identified.2OS3Radiation Monitoring Instrumentation and Protective Equipment (71121.03)

a. Inspection Scope

(1 sample)The inspectors reviewed the Salem Updated Final Safety Analysis Report to identifyapplicable radiation monitors associated with transient high and very high radiation areas, including those used in remote emergency assessment.

b. Findings

No findings of significance were identified.

11Enclosure

OTHER ACTIVITIES

[OA]4OA1Performance Indicator (PI) Verification (71151)

d. Inspection Scope

(6 samples)

Cornerstone:

Mitigating SystemsSafety System Function FailuresThe inspectors reviewed all Salem Unit 1 and 2 licensee event reports issued fromsecond quarter 2004 through the first quarter 2006 for safety system functional failuresas defined by NEI 99-02, "Regulatory Assessment Indicator Guideline," Revision 3.Cornerstone: Barrier IntegrityThe inspectors sampled PSEG submittals for the two PIs listed below for Salem Unit 1and 2. For both PIs, the inspectors reviewed the period from second quarter 2004 through the first quarter 2006. To verify the accuracy of the PI data reported during thatperiod, PI definitions and guidance contained in NEI 99-02, "Regulatory Assessment Indicator Guideline," Revision 3, were used to verify the basis in reporting for each data element.Reactor Coolant System (RCS) Identified Leak RateRCS Specific ActivityThe inspectors reviewed main control room logs and were familiar with identified leakrate data through plant status reviews required by NRC Inspection Manual Chapter2515, Appendix D, "Plant Status." The inspectors also observed a RCS specific activity sample to inspect performance of chemistry technicians and to determine how radio-chemistry results are transferred from field data to the NRC PI report.

b. Findings

No findings of significance were identified.4OA2Identification and Resolution of Problems (71152).1Review of Items Entered into the Corrective Action ProgramAs 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 followup, the inspectors performed a screening of all items entered into PSEG's corrective action program. This was accomplished by reviewing the description of each new notification.

12Enclosure

.2 Semi-Annual Review to Identify Trends

a. Inspection Scope

As required by Inspection Procedure 71152, Identification and Resolution of Problems,the inspectors performed a review of PSEG's corrective action program (CAP) and associated documents to identify trends that could indicate the existence of a moresignificant 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. A specific repetitive equipment issue included low 11 component cooling (CC) header flow rates identified during periodic surveillance testing. The review also included issues documented outside the normal CAP in system health reports, PSEG performance indicators, site monthly managementreview meeting reports and attendance at the Nuclear Review Board. The inspectors' review nominally considered the six-month period of January through June 2006, although some examples expanded beyond those dates when the scope of the trend warranted. Specific documents reviewed are listed in the attachment. b.Assessment and ObservationsNo findings of significance were identified.

For each instance of low 11 CC header flow, PSEG reviewed past operability of the Unit1 residual heat removal system and concluded that operability was always maintai ned. PSEG also considered the potential causes of CC header flow drifting low between surveillance tests and adequately reviewed current operability of the CC system.

PSEGself-identified the repetitive low CC header flow. PSEG initiated long term corrective actions to resolve the issue within corrective action evaluation 70055970..3Annual Sample: Review of Human Performance Improvement Initiative

a. Inspection Scope

The inspectors reviewed PSEG's evaluation of human performance at the Salem andHope Creek sites and the status of corrective actions. The facility initiated notification20265044, "Cross-Cutting Issue (Human Performance)," due to multiple NRC greeninspection findings with a documented human performance aspect plus a determination that human performance deficiencies were involved in fifty percent of Salem licensee event reports for calendar year 2005.The inspectors reviewed the common cause analysis (CCA) completed in response forthis notification, and the notifications and corrective action documentation for theindividual green findings. The CCA considered data from the Salem site, which included all, but one of the human performance related findings. The adequacy of these analyses and corrective actions for both the Salem and Hope Creek sites was evaluated against the performance attributes of NRC inspection procedure 71152.

13Enclosure The inspectors reviewed implementation of the corrective actions. A plan of the day(POD) meeting was observed which included a discussion of a selected human performance tool. The facility implemented the EPRI Proactive Assessment of Organizational and Workplace Factor (PAOWF) software to document work observations. A selection of completed PAOWF observations was reviewed. The inspectors also reviewed lesson plans for human performance fundamentals presented to supervisors and managers and the lesson plan presented to engineering personnel for improvement of apparent cause evaluations.

b. Findings and Observations

No findings of significance were identified.

The CCA considered nine LERs, 12 non-cited violations, 3 findings, and 18 associatedcondition reports describing human performance issues from calendar year 2005. Two common causes were identified: less than adequate utilization of "human performancefundamentals" applicable to individual functional areas, and failure to address and/or identify human performance deficiencies during engineering technical evaluations of plant problems. The review described in this CCA and the human performance improvement initiatives PSEG was undertaking were considered by the inspectors to be thorough. In addition to the common cause corrective actions, specific corrective actions were implemented for each individual issue that prompted the common cause analysis. Some corrective actions to address the common causes included implementation of aHuman Performance Steering Committee, new station procedures directing human performance tools, and the new PAOWF work observation forms which included specific questions to evaluate human performance fundamentals. Training on human performance fundamentals and attention to human performance initiatives were ongoing. Training for engineering department personnel was conducted and intended to improve quality of apparent cause evaluations.Ongoing evaluation by PSEG regarding the effectiveness of these human performanceinitiatives was planned through evaluations of work observation card data and human reliability performance indicators. The inspectors concluded that the value of PAOWFassessment appeared to be highly dependent on how well they were used by the assessor; some cards were simply numerical scores, others contained explanations or commentary. The initial self assessment of the effectiveness of these corrective actions was scheduled for later in 2006, after training completion and PAOWF observation accumulation.

14Enclosure

.4 Annual Sample: Review of Operator Workaround Program

a. Inspection Scope

The inspectors conducted a cumulative review of operator workarounds for Salem Units1 and 2 and assessed the effectiveness of PSEG's operator workaround program.

Particular focus was placed on the potential impact on mitigating systems and thepotential to affect the operators' ability to implement abnormal and emergency operatingprocedures. The review included interviews with licensed operators and walk downs of main control room panels. The inspectors reviewed PSEG's operator burden list, control room distraction report, and operator burden self assessment.

b. Findings and Observations

No findings of significance were identified.

PSEG characterized one item in its operator burden list as an operator workaround. The inspectors did not identify additional operator workarounds. There were 38 of 152 operator burden items classified as operator challenges. The inspectors noted that SH.OP-AP.ZZ-0030, "Operator Burden Program," Revision 8, specified that the quarterly operator burden assessment should include groupings of burdens by system,and that the aggregate impact by system for each watch station should be evaluated todetermine if an individual operator may be overburdened. These items were not documented in the most recent quarterly assessment for either Salem unit.The inspectors observed that the 22 steam generator feed pump (SGFP) suction flowindication was faulted (notification 20261237) and could provide a balance-of-plant challenge to operators during a reactor trip, yet the issue was not captured in the operator burden program. This issue was listed as a priority 4, low level issue, on the control room distractions report. The inspectors also identified informal guidance to reactor operators for the failed 22 SGFP suction flow indication.PSEG initiated corrective action notification 202777133 and temporary standing order06-04 to properly control the 22 SGFP guidance. PSEG also promptly communicated the improper administrative control to all control room operators via a night order entry. PSEG noted the other minor OWA administrative issues. The inspectors concluded that PSEG was making noticeable progress towards reducing operator burdens.

.5 Safety Conscious Work Environment Metric Review

a. Inspection Scope

The inspectors reviewed PSEG's progress in addressing safety conscious workenvironment (SCWE) issues that were discussed in the NRC's annual assessment letterdated March 3, 2006. In that letter, the NRC staff documented a SCWE substantivecross-cutting issue and stated the NRC's intention to continue to monitor progress in thisarea.

15Enclosure On May 10, 2006, the inspectors conducted a sampling review of PSEG's SCWEmetrics, or performance indicators (PIs), for first quarter 2006. Documents reviewed are listed in the attachment.

b. Findings and Observations

No findings of significance were identified.

In first quarter 2006, PSEG identified twenty-four PIs as being green or satisfactorywhile six PIs were identified as red or needing improvement. An additional PI documenting the results of a recent Synergy Consulting Services Corporation survey of the Salem/Hope Creek workforce was added in the first quarter 2006 PIs. The first quarter 2006 PIs indicated an improvement from the fourth quarter 2005 results of twenty-one green PIs and eight red PIs. 4OA3Event Followup (71153 - 1 sample).1(Closed) Licensee Event Report (LER) 05000272/2006-001-00, Salem Unit 1 TurbineTrip - Reactor Trip with Reactor Power Above P-9On March 8, 2006, Salem Unit 1 received an automatic reactor trip from a turbine tripcondition that was caused by an anomalous turbine electronic overspeed signal. The reactor trip actions and plant recovery were performed without complications. This issue was discussed in sections 1R14 and 4OA3.1 of NRC Inspection Report05000272&311/2006002. The anomalous electronic overspeed signal was most likely caused by radio-frequency interference (RFI) or electro-magnetic interference (EMI) by an unknown source. Three turbine overspeed conductors are routed together in a single cable. PSEG established additional administrative controls to reduce the likelihood of RFI or EMI in the cable route area. PSEG also planned to evaluate longer term actions such as additional cable shielding or cable separation for the three turbine overspeed conductors. The LER was reviewed by the inspectors and no findings of significance were identified, and no violations of NRC requirements occurred. PSEGdocumented the root cause evaluation in order 70054731. This LER is closed.4OA5Other Activities.1Implementation of Temporary Instruction (TI) 2515/165 - Operational Readiness ofOffsite Power and Impact on Plant Risk

a. Inspection Scope

The objective of TI 2515/165, "Operational Readiness of Offsite Power and Impact onPlant Risk," was to gather information to support the assessment of nuclear power plant operational readiness of offsite power systems and impact on plant risk. The inspectorsevaluated PSEG procedures against the specific offsite power, risk assessment, and system grid reliability requirements of TI 2515/165. The inspectors also discussed theattributes with PSEG personnel.

16Enclosure The information gathered while completing this TI was forwarded to the Office ofNuclear Reactor Regulation for further review and evaluation on April 3, 2006.

b. Findings

No findings of significance were identified..2(Closed) URI 05000272&311/2005004-01 Chemical Volume Control System (CVCS)Cross-Tie ImplementationURI 05000272&311/2005004-01, Chemical Volume Control System (CVCS) Cross-TieImplementation, was opened pending inspector review of PSEG's corrective actions to resolve maintenance rule scoping, 10 CFR 50.59 safety evaluation, and procedure quality and consistency issues for the CVCS cross-ties between Salem Units 1 and 2.

The inspectors earlier reviewed maintenance rule applicability of the reactor coolant sealinjection function via the cross-tie, CVCS cross-tie operating instructions within several abnormal and emergency operating procedures, and associated 10 CFR 50.59 safety evaluations.The CVCS cross-tie was a plant modification (80029150) to Salem Units 1 and 2 madeoperational in late 2002. PSEG installed the inter-unit cross-tie of the CVCS to provide continued charging flow in a postulated post fire condition. PSEG revalidated a post fire safe shutdown analysis and determined that the existing safe shutdown charging pumpsrequired cable separation or protection upgrades. PSEG stated in evaluation 80029150 that greater plant safety could be achieved by installing a charging cross-tie between the Salem Units rather than protecting impacted cables associated with the chargingsystem. The charging cross-tie resulted in having all active components associated witha new, alternate charging train in a totally separate fire area (i.e. the opposite or unaffected unit). The alternate charging train consisted of the existing non-safety related positive displacement pump and a newly installed CVCS cross-tie, and according to PSEG, provided a suitable fix for addressing postulated fires. When the URI was opened, the inspectors noted utilization of the CVCS cross-tie expanded to non-fireemergency operational scenarios. The inspectors also noticed inconsistent application of the CVCS cross-tie to various abnormal and emergency operating conditions.The inspectors reviewed corrective actions within notifications 20254207, 20253052,20253019, and 20253153 initiated by PSEG in response to the NRC questions. Theinspectors interviewed licensing engineers, maintenance rule engineers and operators with particular focus on RCP seal injection restoration strategies after a total loss of RCP seal cooling condition. The inspectors considered station blackout (SBO), fire, loss of service water, loss of component cooling water, and loss of charging scenarios. The inspectors verified that adequate precautions existed within applicable PSEG operatingprocedures to prevent thermal shock of RCP shaft seals prior to seal injection restoration. Finally, the inspectors reviewed PSEG's RCP seal restoration strategies for SBO, 10 CFR 50 Appendix R fire, and loss of RCP seal cooling scenarios. PSEG determined that because of human reliability considerations, the CVCS cross-tie couldnot be credited for seal injection during SBO and loss of seal cooling events. The time 17Enclosure frame allowed to restore seal injection was not feasible. The inspectors concluded therewere no findings of significance. This URI is closed.4OA6Meetings, Including Exit NRC/PSEG Management Meeting - Reactor Oversight Process Annual Assessment. The NRC conducted a meeting with PSEG on May 17, 2006, to discuss the NRC'sannual assessment of safety performance at Salem and Hope Creek for calendar year 2005, and PSEG actions to improve the safety conscious work environment. The meeting occurred at the Holiday Inn Select in Bridgeport, New Jersey and was open for public observation. A copy of slide presentations and other background documents can be found in ADAMS under accession number ML060680412.Exit Meeting. On July 6, 2006, the resident inspectors presented the inspection resultsto Mr. Tom Joyce, Site Vice President - Salem, and other members of PSEG's staff.

The inspectors verified that no proprietary information is contained in the report.ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee personnel

T. Joyce, Salem Vice President

C. Fricker, Salem Plant Manager

S. Robitski, Salem Engineering Director

T. Gierich, Salem Operations Manger

J. Stone, Salem Maintenance Director

G. Sosson, Salem System Engineering Manager

A. Roberts, Manager - Engineering Programs

R. Gary, Salem Technical Superintendent - Radiation Protection

S. Mannon, Salem Regulatory Assurance Manager

T. Neufang, Radiological Engineering Manager

P. Steinhauer, Training Support Manager

P. Quick, Operational Chemistry Supervisor

J. Melchionna, Generic Letter 89-13 Program Manager

C. Pupek, PRA Engineer

T. Carrier, PRA Engineer

E. Villar, Nuclear Licensing/Compliance

J. Wearne, Nuclear Licensing/Compliance

D. Kabachinski, Emergency Preparedness

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

05000311/2006003-01URI22 Service Water Strainer Multiple Trips (Section1R12)

Opened/Closed

05000272/2006-001-00LER Salem Unit 1 Turbine Trip - Reactor Trip withReactor Power Above P-9 (Section 4OA3.1)

Closed

05000272&311/2005004-01 URIChemical Volume Control System Cross-TieImplementation (Section 4OA5.2)

A-2Attachment

LIST OF DOCUMENTS REVIEWED

In addition to the documents identified in the body of this report, the inspectors reviewed thefollowing documents and records:

Section 1R01: Adverse Weather ProtectionProceduresNC.OP-DG.ZZ-0002, Severe Weather Guide, Revision (Rev.) 6SH.OP-DG.ZZ-0011, Station Seasonal Readiness Guide, Rev. 4

SC.OP-AB.ZZ-0001, Adverse Environmental Conditions, Rev. 9

SC.OP-PT.ZZ-0002, Station Preparations for Seasonal Conditions, Rev. 10

WC-AA-107, Seasonal Readiness, Rev. 2

S2.OP-SO.CBV-0001, Containment Ventilation Operation, Rev. 30

S1.OP-DL.ZZ-0001, Control Room Logs, Rev. 5Notifications

272148,

20281752,

20281787,

20283271,

20283958,

20284189,

20284885, 20286563Orders

80088650,

70049239,

60062651,

60029373,

60046922, Other DocumentsPSEG letter dated May 9, 2006 to Bill Levis from Carl Fricker, re: Salem Station SummerReadiness2006 Salem Summer Readiness Status report Salem Generating Station Environmental Summer Readiness response plan Summer Readiness Just-in-Time Training for Licensed and Non-Licensed Operators

Section 1R04: Equipment AlignmentProceduresS2.OP-AB.CC-0001, Component Cooling Abnormality, Rev. 11S2.OP-SO.CC-0002, 21 & 22 Component Cooling Heat Exchanger Operation, Rev. 192-EOP-APPX-1, Component Cooling Water Restoration, Rev. 23

S2.OP-ST.CVC-0008, Reactivity Control Systems - Boration, Rev. 9

S2.OP-ST.CVC-0009, Reactivity Control Systems - Boration, Rev. 22

S2.OP-ST.CVC-0010, Borated Water Sources, Rev. 8Drawings

205331,

205328

Notifications

280800,

20261197

A-3Attachment Other DocumentsLineup Id 976, Boration Flowpath Validation

Section 1R05: Fire ProtectionProceduresFRS-II-431, Pre-Fire Plan U1 & U2 460V Switchgear Rooms and Corridor, Rev. 6FRS-II-432, Pre-Fire Plan U1 & U2 Spent Fuel/Component Cooling Heat Exchanger & PumpArea, Rev. 5FRS-II-435, Pre-Fire Plan U1 & U2 Diesel Fuel Oil Storage Area, Rev. 5

SC.FP-AP.ZZ-0003, Actions for Inoperable Fire Protection - Salem Station, Rev. 11

NC.FP-AP.ZZ.0020, Compensatory Measure Firewatch Program, Rev. 1Notifications

281144, 20287544

Other DocumentsHourly Fire Watch Patrol Inspection Log dated June 15, 2006Salem and Hope Creek Fire Impairment Log Book

Section 1R06: Flood Protection MeasuresProceduresS1.OP-SO.AF-0001, Auxiliary Feedwater System Operation, Rev. 21SC.FP-ST.FS-0007, Class 1 Fire Water System' Valve Cycling, Rev. 2

SC.FP-SV.FBR-0026, Flood and Fire Barrier Penetration Seal Inspection, Rev. 2Drawings

207095,

207096,

207080,

207081

Notifications

280721,

20281348,

20287431,

20287412,

20287502,

20273398,

20287512,

20287431,

20273733, 2016470Orders

70058383,

30100224,

70042667, 70035088

Other DocumentsUpdated Final Safety Analysis Report section 3.6.5.12Salem Generating Station Individual Plant Examination for External Events dated January 1996,PSEG

VTD 320758-01Flood Assessment for IPEEE of Salem Nuclear Generating Station Units 1 & 2 datedSeptember 29, 1994, PSEG

VTD 320058S-C-A364-CSE-0500-0, Effects on Safety Related Control Equipment Due to Fire ProtectionPiping Failure dated October 29, 1972

A-4Attachment

Section 1R07: Heat Sink PerformanceProceduresNC.ER-AP.ZZ-0039, Service Water Reliability Program, Rev. 1SC.ER-DG.ZZ-0002, System Function Level Maintenance Rule Scoping, Rev. 2

SC.MD-GP.SW-0001, Service Water Silt Survey, Rev. 9

SC.RA.TI.ZZ-0029, Trending Lube Oil Cooler Parameters for Centrifugal Charging, SafetyInjection, Service Water Pumps and Emergency Power Diesel Generators, Rev. 1S1.OP-ST.SW-0005, Inservice Testing - 15 Service Water Pump, Rev. 23

S1.RA-ST.SW-0005, Inservice Testing 15 Service Water Pump Acceptance Criteria, Rev. 9

NC.ER-TI.ZZ-0001, Inspection of Service Water Heat Exchangers, Piping, Flanges andMiscellaneous Valves, Rev. 1S1.OP-DL.ZZ-0006, Primary Plant Log, Rev. 45

S2.OP-PT.SW-0004, Service Water Fouling Monitoring Safety Injection and Charging Pumps,Rev. 8S2.OP-PT.SW-0006, Service Water Fouling Monitoring Diesel Generators, Rev. 9DrawingsVTD

176448-02, Service Water Pump Motor Upper Bearing Cooler

205242

205342Notifications

288028,

20285658,

20285654,

20219903,

20229808,

20235849,

20236105,

20236531,20237939,

20238593,

20245374,

20261312,

20271959, 20285658Orders

30032579,

30044728,

30103346,

30121419,

30138065, 30138353

Other DocumentsNLR -N90021PSEG Letter dated January 26, 1990 to United States Nuclear RegulatoryCommission re: Response to Generic Letter 89-13NLR-N90165, Revised Response to Generic Letter 89-13, Service Water Problems AffectingSafety Related Equipment, Salem Generating Station, dated August 31, 1990PSEG Generic Letter 89-13 White Paper regarding service water reliabilityEPRI

NP-7552, Heat Exchanger Performance Monitoring Guidelines

S-C-SW-MDC-1068, Service Water System Design Basis Temperature, Rev. 3

S-2-ABV-MDC-1697, MDAFW Pump Room Temp Following the Room Cooler Failure, Rev. 2

S-C-ABV-NEE-0504, Engineering Evaluation on the Effect an Inoperable Room Cooler has on the Operability of Vital Pumps, dated December 20, 1990S-C-AF-MEE-1749, Effect of Loss of Room Cooler for Turbine Driven Auxiliary Feedwater Pump Room, Rev. 0S-C-SW-MDC-1068, Service Water System Design Basis Temperature, Rev. 1

S-C-SW-MDC-1860, Reduced Service Water Flow to Safety Injection and Charging Pump Lube Oil and Gear Oil Coolers, Rev.

128443,Heat Exchanger Inspection Report 'C" EDG Lube Oil and Jacket Water Cooler, dated April 10, 2005

A-5Attachment S-1-SW-MEE-1496, Salem Unit 1 No. 1 Aux Feedwater Pump Room Cooler Eddy CurrentInspection 1R14, Rev. 0, dated May 23, 2001S2DG-2DAE3, Eddy Current Inspection Results for 2C Diesel Lube Oil Cooler, dated April 15, 2005S-C-N100-MDM-0315, Replace Speed Increaser Gear Lube Oil Coolers, dated February 14, 1986S-C-N100-NDS-0076, Charging/SI Speed Increaser Gear Lube Oil Coolers, dated September

10, 1986S-C-SW-MDS-0348, Nuclear Safety Injection and/or Charging Pump Lubricating Oil CoolerDetailed Specification, dated November 19, 1998S-C-SW-MEE-1182, Salem Station - Charging Pump Lube Oil Cooler Heat ExchangerSpecification Sheet, dated March 26, 19863rd Quarter 2005 Service Water System Health Report Salem 1

3rd Quarter 2005 Service Water System Health Report Salem 2

4th Quarter 2005 Service Water System Health Report Salem 1

4th Quarter 2005 Service Water System Health Report Salem 2

Plant Health Committee System Presentation - Unit 1 Service Water 1st Quarter 2006

Plant Health Committee System Presentation - Unit 2 Service Water 1st Quarter 2006

Section 1R11: Licensed Operator Requalification ProgramProceduresSalem Event Classification Guide, Rev. 63S2.OP-AB.CC-0001, Component Cooling Abnormality, Rev. 11

2-EOP-TRIP-1, Reactor Trip or Safety Injection, Rev. 25

2-EOP-LOPA-1, Loss of All AC Power, Rev. 25

S2.OP-AR.DG-0002, 2B Diesel Generator Alarm Response Salem Operating Department, Rev.

13Notifications

260710,

20274238, 20286742

Orders

70051642, 70054916

Other DocumentsSimulator Scenario Guide S-ESG-0602, Rev. 0

Section 1R12: Maintenance EffectivenessProceduresSC.ER-DG.ZZ-0002, System Function Level Maintenance Rule Scoping vs. Risk Reference,Rev. 2S1.OP-ST.SW-0005, "Inservice Testing - 15 Service Water Pump," Rev. 22

NC.ER-AP.ZZ-0039, "Service Water Reliability Program," Rev. 1SH.MD-GP.ZZ-0011, Meggering of Rotating Electrical Equipment, Rev. 4

A-6Attachment

SC.MD-PT.230-0001, Thermal Overload Relay Overcurrent Trip Testing, Rev. 2SC.MD-PM.SW-0003, Service Water Auto Strainer Adjustment, Inspection, Repair and Replacement, Rev. 25

SC.OP-DD.ZZ-0006, Protective Circuit/Breaker Reset and Reclosure Policy, Rev. 0Notifications

286043,

20275072,

20275035,

20275390,

20031405,

20247761,

20082332,

20285561,

20289327,

20289407,

20288573,

20275035,

20275118,

20280934,

20194299, 20288491Orders

70036522,

70055065,

70033927,

70007766,

60062841,

30137220,

70057833,

80009391, 30136477Other DocumentsNRC Generic Letter 89-13, "Service Water System Problems Affecting Safety-RelatedEquipment"EPRI

NP-7552, "Heat Exchanger Performance Monitoring Guidelines"

VTD 320202, Service Water Pump Application List

VTD 306208, Installation, Operating & Maintenance Manual for S.W. Strainers, Serial No.6168-6180

Section 1R13: Maintenance Risk Assessments and Emergent Work ControlProceduresSH.OP-AP.ZZ-0027, On-Line Risk Assessment, Rev. 10WC-AA-101, On-Line Work Control Process, Rev. 11

NC.CC-DG.ZZ-0003, PRA Weekly Risk Assessment (a)(4) Desktop Guide, Rev. 4

NC.WM-AP.ZZ-0001, Work Management Process, Rev. 12

WC-AA-101, Exelon's On-line Work Control Process, Rev. 11

S1.OP-SO.PC-0001, Switchgear and Penetration Areas Ventilation Operation, Rev. 13Notifications

285671

Other DocumentsCompleted Salem Generating Station Weekly Risk Evaluation FormsRisk-Informed Inspection Notebook For Salem Generating Station, Rev. 2

PRA Risk Evaluation Forms (published weekly on PSEG LAN website)

Protected Equipment/Heightened Awareness Log Operations Department Night Orders of Tuesday, April 25, 2006

Section 1R15: Operability EvaluationsProceduresSH.OP-AP.ZZ-0108, Operability Assessment and Equipment Control Program, Rev. 24

A-7Attachment Drawings

205337,

611003, 218664Notifications

285394,

20285636,

20285638,

20285254,

20005823,

20185075,

20251471,

20276469,

20284189,

20237806,

20272927,

20276480,

20255139,

20263228,

20252333,

20255146,

20280010,

20276147,

20288355,

20288356,

20288357,

20288358,

20288646, 20288587Orders

70038389,

70050150,

70055356,

70055356,

70057799,

80088928,

70047446,

70054581,

70050779,

70057799, 60061674Other DocumentsMPR Associates, Inc. root cause report of the jacket water leak on the 1C emergency dieselgenerator 5L cylinder head dated October 12, 2005Adverse Condition Monitoring and Contingency Plan (ACM)06-010

ACM 06-017

Westinghouse Electric Company letter

LTR-NRC-05-44, Rev. 1, dated February 9, 2005PSEG Calculation S-2-AUX-MDC-1627, Pipe Break Pressures in Auxiliary Building RoomsCROD 05-020 (70050799), 1ABS4 Damper Stuck in Mid Position

CROD 06-13 (70057799), Reliability of Salem Unit 1 and 2 EDGs with potentially degradedheads supplied by Canada Allied Diesel

Section 1R19: Post-Maintenance TestingProcedures

NC.MD-AP.ZZ-0050, Maintenance Testing Program Matrix, Rev. 6

NC.NA-AP.ZZ-0050, Station Post Maintenance Testing, Rev. 7

S2.OP-ST.CC-0002, Inservice Testing - 22 Component Cooling Pump, Rev. 20

S2.RA-ST.CC-0002, Inservice Testing - 22 CC Pump Acceptance Criteria, Rev. 14

SC.MD-CM.DG-0002, Emergency Diesel Generator Cylinder Head Replacement, Revs. 4 & 5

S1.OP-ST.DG-0003, 1C Diesel Generator Surveillance Test, Rev. 42SC.MD-ST.125-0003, Quarterly Inspection and Preventive Maintenance of Units 1, 2 & 3 125Volt Station Batteries, Rev. 22SC.MD-CM.125-0005, 125VDC Vital Battery Cell Replacement, Rev. 7

S1.OP-ST.125-0001, Electrical Power Systems 125VDC Distribution, Rev. 10

SH.MD-GP.ZZ-0240, System Pressure Test at Normal Operating Pressure and Temperature,Rev. 7SH.MD-SP.ZZ-0002, Use of Freeze Seals, Rev. 3

NC.CC-AP.ZZ-0080, Engineering Change Process, Rev. 18

SC.MD-PM.ZZ-0052, Disassembly, Inspection and Reassembly of Velan Swing Check ValvesMark #s A-160, A-165, A-224,

AA-64,

AA-121,

AA-122,

AA-153, E-6,

EA-8,

FA-33 andFA-34, Rev. 5S2.OP-ST.CVC-0004, Inservice Testing - 22 Charging Pump, Rev. 20

S1.OP-ST.SW-0002, Inservice Testing - 12 Service Water Pump, Rev. 23

S1.RA-ST.SW-0002, Inservice Testing 12 Service Water Pump Acceptance Criteria, Rev. 7

A-8Attachment Notifications

278547,

20282082,

20260268,

20270268,

20281879,

20280766,

20280788,

20279828,

20283434,

20052643,

20032801, 20270528Orders

60061092,

60062825,

60062984,

60061996,

60060740,

50093207,

60060959,

80034597,

80022704,

80022704,

30074181,

30074221,

30107211,

30124651,

30132800,

30134087, 70053556Other DocumentsAdverse Condition Monitoring Plan 05-008, Charging Pump Check Valve Back LeakageSalem Inservice Testing Program Basis Data Sheets for 12SW24Section 1R22: Surveillance TestingProceduresSC.MD-ST.125-0003, Quarterly Inspection and Preventive Maintenance of Units 1, 2 & 3 125Volt Station Batteries, Rev. 22S2.OP-ST.DG-0002, 2B Diesel Generator Surveillance Test, Rev. 43S2.RA-ST.DG-0002, 2B Diesel Generator Surveillance Test Acceptance Criteria, Rev. 3S2.OP-ST.DG-0013, 2B Diesel Generator Endurance Run, Rev. 23

S2.OP-ST.DG-0020, 2B Diesel Generator Hot Restart Test, Rev. 11

S1.OP-ST.DG-0003, 1C Diesel Generator Surveillance Test, Rev. 42S1.RA-ST.DG-0003, 1C Diesel Generator Surveillance Test Acceptance Criteria, Rev. 5S2.OP-ST.RHR-0001, Inservice Testing - 21 Residual Heat Removal Pump, Rev. 20S2.RA-ST.RHR-0001, Inservice Testing 21 Residual Heat Removal Pump Acceptance Criteria,Rev. 7S2.OP-ST.AF-0003, Inservice Testing - 23 Auxiliary Feedwater Pump, Rev. 41S2.OP-ST.AF-0003, Inservice Testing - 23 Auxiliary Feedwater Pump, Rev. 42S2.RA-ST.AF-0003, Inservice Testing 23 Auxiliary Feedwater Pump Acceptance Criteria, Rev.

16S2.OP-ST.AF-0002, Auxiliary Feedwater Backleakage, Rev. 8S1.OP-ST.CVC-0003, Inservice Testing - 11 Charging Pump, Rev. 17

S1.RA-ST.CVC-0003, Inservice Testing 11 Charging Pump Acceptance Criteria, Rev. 8Drawings

205303

Notifications

279193,

20279009,

20279127,

20283150,

20208030,

20281590,

20270956,

20265800,

20265861,

20276816, 20267219Orders

50093126,

50083926,

50083906,

50090925,

50093004,

50094225,

30122885,

30102967,

40023364,

50093561,

70037915,

50094702

A-9Attachment

Section 1EP6: Drill EvaluationProceduresSalem Event Classification Guide, Rev. 63NC.EP-EP.ZZ-0102, Emergency Coordinator Response, Rev. 11

NC.EP-EP.ZZ-0401, Emergency Preparedness Coordinator Response, Rev. 3Notifications

287764

Other DocumentsSalem full drill S06-03 critique notes dated June 7, 2006Section 2OS1: Access Control to Radiologically Significant AreasNotifications

259540,

20259550,

20262064,

20263536,

20263574,

20264198,

20264315,

20264800,

20267305,

20267909,

20270397,

20114071,

20124320,

20272974, 20283233Other DocumentsNuclear Oversight Audit

NOSA-SLM-05-06, Salem Radiation Protection Function AreaOngoing Self-Assessment Reports:

80077786-0010, 80077786-0020, 80077786-0090, 80077786-0100Quality Assurance Assessment Reports:

2005-0042, 2005-0053, 2005-0047

Radiological Survey Maps: #1407808 (dat ed 4/13/06, 2/23/06); #1407800 (dated 5/4/06,4/27/06; #11064-Q (dated 2/8/06)

Section 2OS2: ALARA Planning and ControlsOther DocumentsALARA Review 2006-23, Painting in Unit 2

RHR Pit (Elevations 55' and 45')Section 2OS3: Radiation Monitoring InstrumentationOther DocumentsUFSAR Section 11.4, Radiological Monitoring

Section 4OA1: Performance Indicator VerificationProceduresNC.CH-RC.ZZ-2525, Gamma Spectroscopy Analysis Using

CAS, Rev. 4SC.CH-SA.ZZ-0208, Radiochemical Sample Preparation, Rev. 10

SC.CH-SA.CVC-0221, CVCS Demineralizer Sampling, Rev. 6

SC.CH-SA.RC-0222, Sampling Reactor Coolant and RHR Heat Exchanger Outlet, Rev. 16Notifications

A-10Attachment

287861

Section 4OA2: Identification and Resolution of ProblemsProceduresHU-AA-1081, Rev. 0, Fundamentals Tool KitHU-AA-101, Rev. 3, Human Performance Tools and Verification Practices

HU-AA-102, Rev. 1, Technical Human Performance Practices

HU-AA-1212,

Rev. 1, Technical Task Risk/Rigor Assessment, Pre-Job Brief,Independent Third Party Review, and Post-Job BriefHU-AA-1101, Rev. 1, Change Management

HU-AA-104-101, Rev. 1, Procedure Use and Adherence

HU-AA-1211, Rev. 2, Briefings - Pre-Job, Heightened Level of Awareness,Infrequent Plant Activity, and Post-Job BriefingsS1.OP-ST.CC-0003, Inservice Testing Component Cooling Pump, Rev. 18

SH.OP-AP.ZZ-0030, Operator Burden Program, Rev. 8Notifications

265044,

20216735,

20235815,

20250244,

20233706,

20261768,

20259571,

20260710,

20256302,

20263496,

20285228,

20279126,

20218230,

20267739,

20265473,

20249632,

20214271,

20261237, 202777133Orders

70055970,

70045648, 70043024

Other DocumentsHuman performance improvement lesson plans and presentation materialsHuman Performance Fundamentals - powerpoint presentation

S-1-CC-MDC-1817, "Component Cooling System Thermal-Hydraulic Analysis - Unit 1," Rev. 4

S-1-CC-MEE-1281, "Component Cooling Safety Load Flow Requirements - Unit 1," Rev. 0

Quarterly Operator Burden Assessment, First Quarter 2006, Unit 1 and Unit 2

PSEG Metrics for Improving the Work Environment, Salem and Hope Creek GeneratingStations, Quarterly Report, April 28, 2006Salem Unit 1 Unplanned Shutdown LCO Entries PI for January, 2006 and February, 2006

Salem Unit 2 Unplanned Shutdown LCO Entries PI for January, 2006 and February, 2006

Temporary Standing Order 06-04 dated April 1, 2006

Section 4OA5: Other ActivitiesProceduresNC.WM-AP.ZZ-0001, Work Management Process, Rev. 12NC-CC-DG.ZZ-0003,

PRA Weekly Risk Assessment (a)(4) Desktop Guide, Rev 3

S1.OP-AB.GRID-0001, Abnormal Grid, Rev. 16

SH.OP-AP.ZZ-0027, On-Line Risk Assessment, Rev. 9

SH.OP-DD.ZZ-0001, Electric System Emergency Operations and Electric System OperatorInterface, Rev. 3

A-11Attachment

WC-AA-101, On-Line Work Control Process, Rev. 11Notifications

253052,

20216063,

20254207,

20265691, 20262452

Orders

70050691, 80084855

LIST OF ACRONYMS

ALARAAs Low As Is Reasonably AchievableASMEAmerican Society of Mechanical Engineers

CAPCorrective Action Program

CCComponent Cooling

CCACommon Cause Analysis

CCWComponent Cooling Water

CFRCode of Federal Regulations

CVCSChemical Volume Control System

EDGEmergency Diesel Generator

EPRIElectric Power Research Institute

LERLicensee Event Report

MRMaintenance Rule

NCVNon-cited Violation

NRCNuclear Regulatory Commission

ODOperability Determination

PAOWFProactive Assessment of Organizational and Workplace Factor

PARSPublicly Available Records

PIPerformance Indicator

PODPlan of the Day

PSEGP ublic Service Enterprise Group Nuclear

LLC [[]]

RCSReactor Coolant System

SBOStation Blackout

SCWESafety Conscious Work Environment

SDPSignificance Determination Process

SGFPSteam Generator Feed Pump

SWSService Water Strainer

TITemporary Instruction

UFSARUpdated Final Safety Assessment Report

URIUnresolved Item

VTDVendor Technical Document

WOW ork Order