IR 05000354/2006003

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July 21, 2006

Mr. William LevisSenior Vice President and Chief Nuclear Officer PSEG LLC - N09 P. O. Box 236 Hancocks Bridge, NJ 08038

SUBJECT: HOPE CREEK GENERATING STATION - NRC INTEGRATED INSPECTIONREPORT 05000354/2006003

Dear Mr. Levis:

On June 30, 2006, the US Nuclear Regulatory Commission (NRC) completed an inspection atyour Hope Creek Generating Station. The enclosed integrated inspection report documents theinspection findings, which were discussed on July 6, 2006, with Mr. George Barnes 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. This report documents one NRC-identified finding and two self-revealing findings of very lowsafety significance (Green). These findings were determined to involve violations of NRC requirements. However, because of the very low safety significance and because they are entered into your corrective action program, the NRC is treating these three findings as non-cited violations (NCVs) consistent with Section VI.A.1 of the NRC Enforcement Policy. Ifyou 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 Hope CreekGenerating Station.In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter and itsenclosure, and your response (if any) will be available electronically for public inspection in the Mr. W. Levis22NRC Public Document Room or from the Publicly Available Records (PARS) component ofNRC'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, ChiefProjects Branch 3 Division of Reactor ProjectsDocket No:50-354License No:NPF-57

Enclosure:

Inspection Report 05000354/2006003

w/Attachment:

Supplemental Informationcc w/encl:G. Barnes, Site Vice President D. Winchester, Vice President - Nuclear Assessments W. F. Sperry, Director - Business Support D. Benyak, Director - Regulatory Assurance M. Massaro, Hope Creek Plant Manager J. J. Keenan, Esquire M. Wetterhahn, Esquire Consumer Advocate, Office of Consumer Advocate F. Pompper, Chief of Police and Emergency Management Coordinator P. Baldauf, Assistant Director of 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 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

...................................................iii

REACTOR SAFETY.........................................................11R01Adverse Weather Protection.......................................1 1R04Equipment Alignment.............................................1 1R05Fire Protection..................................................2 1R06Flood Protection Measures........................................31R07Heat Sink Performance...........................................3 1R08Inservice Inspection Activities......................................3 1R11Licensed Operator Requalification Program...........................41R12Maintenance Effectiveness........................................51R13Maintenance Risk Assessments and Emergent Work Control..............51R14Operator Performance During Non-Routine Evolutions and Events.........81R15Operability Evaluations..........................................101R17Permanent Plant Modifications....................................101R19Post-Maintenance Testing........................................111R20Refueling and Other Outage Activities...............................121R22Surveillance Testing............................................15 1R23Temporary Plant Modifications....................................16 1EP6Drill Evaluation.................................................16RADIATION SAFETY.......................................................172OS1Access Control to Radiologically Significant Areas.....................17 2OS2ALARA Planning and Controls.....................................192OS3Radiation Monitoring Instrumentation and Protective Equipment..........20OTHER ACTIVITIES........................................................204OA1Performance Indicator Verification..................................20 4OA2Identification and Resolution of Problems............................214OA5Other Activities.................................................24 4OA6Meetings, Including Exit..........................................25SUPPLEMENTAL INFORMATION............................................A-1KEY POINTS OF CONTACT................................................A-1 LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED...........................A-1LIST OF DOCUMENTS REVIEWED..........................................A-2 LIST OF ACRONYMS.....................................................A-20 EnclosureiiiSUMMARY OF FINDINGSIR 05000354/2006003; 04/01/2006 - 06/30/2006; Hope Creek Generating Station; MaintenanceRisk Assessments and Emergent Work Control, Refueling and Other Outage Activities, and Access Control to Radiologically Significant Areas.The report covered a 3 month period of inspection by resident inspectors and announcedinspections by a regional senior health physics inspector, two regional senior reactor inspectors and three regional reactor inspectors. Three Green non-cited violations (NCVs) 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 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

Cornerstone: Mitigating Systems

Green.

Inspectors identified a non-cited violation of 10 CFR 50, Appendix B,Criterion XVI, "Corrective Action," when the 'A' service water strainer was rendered unavailable on April 18, 2006. On November 25, 2004, the 'C' servicewater strainer backwash arm motor experienced elevated running current and multiple thermal overload trips. PSEG performed design change and corrective maintenance activities to increase the size of the thermal overloads for the 'C'

strainer motor. This condition adverse to quality was not entered into PSEG's corrective action program (CAP) for evaluation and extent of condition review.

On April 18, 2006, PSEG experienced elevated running current and multiple thermal overload trips on the 'A' strainer motor which resulted in unplanned unavailability. PSEG's corrective actions included corrective maintenance toincrease the size of the thermal overloads on the 'A', 'B', and 'D' strainer motorsand evaluations of the elevated motor currents and the CAP oversight issue.This performance deficiency is more than minor because it is associated with theequipment performance attribute and affected the Mitigating Systems cornerstone objective to ensure the availability, reliability, and capability ofsystems that respond to initiating events to prevent undesirable consequences. In accordance with NRC Inspection Manual Chapter 0609, Appendix G,"Shutdown Operation Significance Determination Process," the inspectors conducted a Phase 1 SDP screening and determined that, since adequate mitigation capability was maintained and a quantitative assessment was notrequired, the finding was of very low safety significance (Green). The performance deficiency had a cross-cutting aspect in the area of problem identification and resolution because PSEG did not evaluate and implement corrective action for a condition adverse to quality. (Section 1R13)

EnclosureivGreen. A self-revealing non-cited violation of 10 CFR 50, Appendix B, CriterionV, "Instructions, Procedures, and Drawings," was identified when the single source of shutdown reactor water level indication was rendered inaccurate during reactor vessel reassembly. PSEG's refueling maintenance procedure directed the installation of blank flanges on all reactor vessel head penetrations during reactor disassembly. This resulted in the reactor being placed in an unvented condition when the head was reinstalled on the vessel which caused the shutdown reactor water level indication to be inaccurate and invalid. PSEG's corrective actions included changes to the refueling maintenance procedures to install vented flanges and changes to the integrated operations procedures to ensure that the reactor is vented prior to changing vessel level in Operational Condition 4 or 5.This performance deficiency is more than minor because it is associated with theequipment performance attribute and affected the Mitigating Systems cornerstone objective to ensure the availability, reliability, and capability ofsystems that respond to initiating events to prevent undesirable consequences. In accordance with NRC Inspection Manual Chapter 0609, Appendix G,"Shutdown Operation Significance Determination Process," the inspectors conducted a Phase 1 SDP screening and determined that, since adequate mitigation capability was maintained and a quantitative assessment was notrequired, the finding was of very low safety significance (Green). The performance deficiency had a cross-cutting aspect in the area of human performance because PSEG did not provide adequate procedure resources to prevent the loss of all shutdown range reactor water level indication.

(Section 1R20)

Cornerstone: Occupational Radiation Safety

Green.

A self-revealing non-cited violation of 10 CFR 20.1501, "Surveys andMonitoring: General", was identified when a worker's electronic dosimeter alarmed due to dose rates in the 'A' steam jet air ejector (SJAE) room exceeding the preset alarm setpoint. During power ascension at the end of the refueling outage, the worker entered the 'A' SJAE room and received a dose rate alarm due to the presence of dose rates in excess of 100 millirem per hour measured30 centimeters from the source of radiation although the rooms were notidentified, posted or controlled as a high radiation area. Changing radiologicalconditions caused by changes in reactor power level and increased steam flow in the plant required that a new radiological survey of the 'A' SJAE room be conducted in accordance with 10 CFR 20.1501 to support compliance with 10 CFR 20.1201, "Occupational Dose Limits for Adults," and plant technical specification 6.12.1, prior to personnel entry. PSEG's corrective actions included implementing process controls requiring the posting of select steam affected areas upon reactor criticality.The failure to survey an area subject to changing radiological conditions inaccordance with 10 CFR 20.1501 to ensure compliance with the requirements of 10 CFR 20.1201, and to accurately brief workers entering a posted high radiation Enclosurevarea (Plant Technical Specification 6.12) on the radiological conditions wasdetermined to be a performance deficiency and a finding. The finding is more than minor because it is associated with the occupational radiation safety cornerstone attribute of exposure control and affected the cornerstone objective of providing adequate protection of workers from exposure to radiation.

Because the performance deficiency involved a worker entering an uncontrolled high radiation area, the finding was evaluated using Inspection Manual Chapter (IMC) 0609, Appendix C, "Occupational Radiation Safety Significance Determination Process." The inspectors determined that the finding was of very low safety significance (Green), because it did not involve (1) ALARA planning and controls, (2) an overexposure, (3) a substantial potential for anoverexposure, or (4) an impaired ability to assess dose. The performance deficiency had a cross-cutting aspect related to human performance.

Specifically, PSEG did not correctly coordinate surveys and postings of the

'A' SJAE rooms following reactor criticality and startup. (Section 2OS1)

B.Licensee Identified Violations

None.

Enclosure

REPORT DETAILS

Summary of Plant StatusThe Hope Creek Generating Station began the inspection period operating at 100% power. On April 6, 2006, the reactor was shutdown to begin Hope Creek's thirteenth refueling outage(RF13). Hope Creek completed the refueling outage and returned to 100% power on May 12, 2006. Hope Creek operated at 100% power for the remainder of the inspection period.1.REACTOR SAFETYCornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity1R01Adverse Weather Protection (71111.01)

a. Inspection Scope

(1 sample)The inspectors performed a detailed review of PSEG's seasonal readiness proceduresand reviews associated with hot weather conditions. The inspectors reviewed the Updated Final Safety Analysis Report (UFSAR), Technical Specifications, and station procedures to identify system operation in extreme hot weather conditions. Stationprocedures and system health reports were reviewed, and systems that could be subjectto increased heat conditions were walked down to assess reliability and availabilityduring periods of extreme heat. The inspectors focused on the readiness of the station service water, control area chilled water, circulating water, and electrical switch-yard system health. This inspection sample satisfied the inspection requirement to review2 - 4 risk significant systems prior to the onset of hot weather. Documents reviewed are listed in the attachment.

b. Findings

No findings of significance were identified.

1R04 Equipment Alignment (71111.04).1Partial Walkdown (3 samples)

a. Inspection Scope

The inspectors reviewed the status of the following three systems to verify theoperability of redundant or diverse trains and components when other safety equipmentwas inoperable. The inspectors also selected single-train systems to verify operability following periods of maintenance or plant conditions that increased the risk worth of the system. The inspectors reviewed applicable operating procedures, walked down controlsystem components, and verified that selected breakers, valves, and support equipmentwere in the correct position to support system operation. The inspectors also verifiedthat PSEG had properly identified and resolved equipment alignment problems that 2Enclosurecould cause initiating events or impact the capability of mitigating systems or barriersand entered them into the corrective action program. Documents reviewed are listed in the attachment.'D' residual heat removal train when 'B' train was aligned for shutdown cooling onApril 26, 2006'B' & 'D' service water trains when 'C' service water train was out-of-service formaintenance on June 1, 2006High pressure coolant injection (HPCI) system on June 7, 2006

b. Findings

No findings of significance were identified.

1R05 Fire Protection (71111.05).1Fire Protection - Tours

a. Inspection Scope

(9 samples)The inspectors conducted a tour of the nine areas listed below 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; that 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.Motor control center area, elevation 102B' reactor water recirculation pump motor generator set roomStandby liquid control area'C' residual heat removal heat (RHR) pump room'D' residual heat removal heat (RHR) pump room'A' containment instrument gas compressor room'A' and 'C' 125V battery and battery charger roomsLower control equipment roomRemote shutdown facility

b. Findings

No findings of significance were identified.

3Enclosure1R06Flood Protection Measures (71111.06).1External Flooding

a. Inspection Scope

(1 sample)The inspectors reviewed the design, material condition, and procedures for coping withthe design basis probable maximum flood. The inspectors reviewed the UFSAR to determine the barriers required to mitigate flooding in the emergency diesel generator (EDG) areas. The inspectors also reviewed procedures, walked down affected areas and inspected the water tight doors which are required to ensure the EDGs and other safety-related equipment would remain available following the probable maximum flood.

Additionally, the inspectors reviewed the maintenance history of the water tight doors in the area to determine whether they were adequately maintained to protect safety-related equipment during postulated external flood conditions.

b. Findings

No findings of significance were identified.

1R07 Heat Sink Performance (71111.07)

a. Inspection Scope

(1 sample)The inspectors reviewed PSEG's program for maintenance and testing of risk-importantheat exchangers in the safety auxiliary cooling system (SACS). Specifically, the reviewincluded the residual heat removal (RHR) pump motor bearing coolers and seal coolers. The inspectors reviewed calculations, procedures, test results, and vendor documentation to ensure that the coolers would provide adequate heat removal from themotor thrust bearings and the RHR pump seals. The inspectors also reviewed theresults of recent SACS chemistry samples. Documents reviewed are listed in the attachment.

b. Findings

No findings of significance were identified.

1R08 Inservice Inspection Activities (71111.08)

a. Inspection Scope

(1 sample)The inspectors observed selected samples of in-process nondestructive examination(NDE) activities. The inspectors also reviewed documentation of additional samples of NDE and component replacement activities which involved welding processes. 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 increasein risk of core damage. The observations and documentation review were performed to 4Enclosureverify activities were performed in accordance with the American Society of MechanicalEngineers (ASME) Boiler and Pressure Vessel Code requirements. The inspectors reviewed a sample of inspection reports initiated as a result of nonconforming conditions identified during Inservice Inspection (ISI) examinations. Also, the inspectors evaluated effectiveness in the resolution of problems identified during ISI activities.The inspectors observed remote visual (VT) inspection of the steam dryer. Theinspectors also witnessed the installation of a jet pump clamp on jet pump #6. The inspectors reviewed the records of liquid penetrant (LP) examinations, ultrasonic (UT)examinations and visual examinations (VT). Additionally, the inspectors witnessed the testing of several hydraulic snubbers to verify effectiveness of the examiner, test equipment and process in identifying degradation of risk significant systems, structuresand components and to evaluate those activities for compliance with the requirements of ASME Section XI of the Boiler and Pressure Vessel Code.The inspectors selected a sample of notifications for review as representative of anonconforming condition that was evaluated and dispositioned "accept as is" for continued service without repair. Five crack indications on the steam dryer were recordable and dispositioned "accept as-is" for continued service without repair. All of these indications have reinspection requirements during the next refueling outage. The inspectors assessed PSEG's evaluation and disposition for continued service without repair of a non-conforming condition identified during ISI activities.PSEG replaced the 'B' reactor recirculation pump rotating element during refuelingoutage 13. The rotating element primarily consisted of the pump shaft, pump impeller, and parts of the pump seal package. The inspectors reviewed the video-recorded visual examination of the interior of the pump volute. No abnormal indication of wear or any other anomalies were noted. PSEG has accepted this component as acceptable forfurther use. The inspectors concluded that this remote visual examination met the requirements of ASME Section XI.

b. Findings

No findings of significance were identified.

1R11 Licensed Operator Requalification Program (71111.11)

a. Inspection Scope

(1 sample)Resident Inspector Quarterly ReviewOn June 11, 2006, the inspectors observed a simulator training scenario to assessoperator performance and training effectiveness. The scenario involved a reactor recirculation pump trip, a reactor coolant leak in the reactor water clean up system, aloss of the primary containment instrument gas system, and a failure of the reactorprotection system to scram the reactor. The inspectors assessed simulator fidelity and observed the simulator instructor's critique of operator performance. The inspectors 5Enclosurealso observed control room activities with emphasis on simulator identified areas forimprovement identified by PSEG self-assessments and third-party assessments.

Documents reviewed are listed in the attachment.

b. Findings

No findings of significance were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

(2 samples)The inspectors reviewed the two samples listed below for items such as: (1) appropriatework practices; (2) identifying and addressing common cause failures; (3) scoping in accordance with 10 CFR 50.65(b) of the maintenance rule (MR); (4) characterizing reliability issues for performance; (5) trending key parameters for condition monitoring;(6) charging unavailability for performance; (7) classification and reclassification inaccordance with 10 CFR 50.65(a)(1) or (a)(2); and (8) appropriateness of performance criteria for structures, systems, and components (SSCs)/functions classified as (a)(2)and/or appropriateness and adequacy of goals and corrective actions for structures, systems, and components (SSCs)/functions classified as (a)(1). In addition, theinspectors specifically reviewed events where ineffective equipment maintenance has resulted in invalid automatic actuations of Engineered Safeguards Systems affecting the operating units. Documents reviewed are listed in the Attachment. Items reviewed included the following:*125 Volt inverter system based on failure of the 1AD482 inverter section onMarch 27, 2006*'C' emergency diesel generator based on failure of the associated lube oilkeepwarm pump mechanical seal on April 23, 2006

b. Findings

No findings of significance were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

(7 samples)The inspectors reviewed seven on-line risk management evaluations through directobservation and document reviews for the following configurations:'D' EDG inoperable, 'B' filtration, recirculation and ventilation system (FRVS) faninoperable and plant cooldown in progress on April 9, 2006Natural circulation operations concurrent with 'B' & 'D' channel outage workwindows on April 13, 2006 6Enclosure'A' and 'C' channel outage work windows with 'A' (Loss of Power/Loss of CoolantAccident (LOP/LOCA) test in progress on April 23, 2006Loss of the 'A' service water train while 'B' and 'D' service water trains weretagged out for outage related maintenance on April 18, 2006'B' service water train unavailable with one source of offsite power unavailabledue to work on the 13kV 1-2 breaker on May 9, 2006'C' service water pump out-of-service with degraded service water ventilationtrain performance in the 'B' and 'D' service water pump bays on June 1, 2006Diesel fire pump inoperable on June 11, 2006The inspectors reviewed the applicable risk evaluations, work schedules, and controlroom 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 gain insights into the risk associated with these plant configurations. Finally, the inspectors reviewed notifications and associated evaluations documenting problems associated with riskassessments and emergent work evaluations. Documents reviewed are listed in the attachment.

b. Findings

Introduction:

A Green self-revealing non-cited violation of 10 CFR 50, Appendix B,Criterion XVI, "Corrective Action," was identified when the 'A' service water strainer motor tripped on thermal overload (TOL) twice resulting in the 'A' strainer being removed from service for emergent repair.Description: On April 17, 2006, with the unit shutdown, the 'A' service water strainermotor tripped on TOL. PSEG determined the tripping of the strainer was due to improperly sized thermal overloads.The inspectors reviewed this issue and determined that on September 25, 2004, PSEGinstalled a new 2.0 amp motor for the 'B' service water strainer. On October 7, 2004, PSEG identified the strainer was experiencing slightly elevated running current at 2.05amps. PSEG evaluated this condition and determined that the slightly higher currentwas expected due to changes in strainer load while in service. This evaluation also stated that the existing Cutler Hammer H1022 (Lo) TOL size was appropriate.On November 25, 2004, PSEG installed a new 2.0 amp motor on the 'C' service waterstrainer, identified elevated running currents as high as 2.4 amps, and responded to multiple TOL trips during post-maintenance testing. The remaining strainer motors were scheduled for replacement during other maintenance periods. PSEG performed a design change package (DCP) to increase the TOL size to "H1023." The 'C' strainertripped again and PSEG revised the DCP to further increase the size to "H1024." The new H1024 TOLs were installed in the 'C' strainer motor on December 2, 2004. Theinspectors identified that PSEG did not conduct an evaluation and extent of condition 7Enclosurereview for this condition adverse to quality as required by their notification and correctiveaction procedures.PSEG replaced the 'A' and 'D' strainer motors on May 8 and 23, 2005, respectively. Asof May 23, 2005, PSEG had new 2.0 amp motors in all four strainers, but had lower rated H1022 TOLs in the circuitry for the 'A', 'B', and 'D' strainer motors in contrast tothe H1024 TOLs in the 'C' strainer motor circuitry.On April 18, 2006, the 'A' strainer motor TOLs tripped twice resulting in unplannedunavailability of the 'A' strainer. The H1024 TOLs were evaluated by PSEG to beacceptable for all service water strainer motors. PSEG replaced the 'A' strainer TOLs and restored the service water train to an operable status on April 19, 2006. However, as was done in November 2004, PSEG did not conduct an evaluation and extent of condition review to implement corrective action for a condition adverse to quality. The inspectors questioned cognizant PSEG operations, engineering, and maintenance personnel regarding evaluation of this condition and whether an extent of condition review was warranted for the 'B' and 'D' strainer motors which still had the H1022 TOLsinstalled. Subsequently PSEG wrote notifications to conduct operability reviews on the'B' and 'D' service water strainers and to evaluate the multiple TOL trips of the 'A'strainer. PSEG determined that the apparent cause of the 'A' strainer TOL trips inApril 2006 was the failure to conduct an evaluation and extent of condition review of the

'C' strainer TOL trips in November 2004.Analysis: The inspectors determined that the failure to evaluate and implementcorrective actions for a condition adverse to quality resulted in 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> of unplanned unavailability for the 'A' service water strainer in April 2006 and constitutes aperformance deficiency. Because PSEG did not, in accordance with their procedures, evaluate and perform an extent of condition review for multiple trips of the 'C' strainermotor, they did not implement corrective actions to prevent a similar condition in the 'A' strainer.This issue is more than minor because it is associated with the equipment performanceattribute of the mitigating systems cornerstone and affected the cornerstone's objectiveto ensure the availability, reliability, and capability of systems that respond to initiatingevents to prevent undesirable consequences.In accordance with NRC Inspection Manual Chapter 0609, Appendix G, "ShutdownOperations Significance Determination Process," Attachment 1, Checklist 7, the inspectors conducted a Phase 1 SDP screening and determined the finding to be of very low safety significance (Green). The inspectors verified PSEG's shutdown mitigation capability and determined that the finding was not similar to those requiring a Phase 2 orPhase 3 analysis. This finding had a cross-cutting aspect in problem identification and resolution because PSEG did not adequately implement corrective action for a condition adverse to quality. Specifically, PSEG did not conduct an evaluation and implement corrective action for the elevated running current and subsequent multiple TOL trip condition of the 'C' service water strainer motor.

8EnclosureEnforcement: 10 CFR 50 Appendix B, Criterion XVI, "Corrective Action," requires, inpart, that measures shall be established to assure that conditions adverse to quality are promptly identified and corrected. Contrary to the above, PSEG did not implementcorrective action for the elevated running current and multiple TOL trip condition of the

'C' service water strainer motor on November 25, 2004. As a result, the 'A' servicewater train strainer motor experienced elevated running current and multiple TOL trips and accrued 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> of unplanned unavailability on April 18, 2006. PSEG' s correctiveactions included corrective maintenance activities to increase the size of the thermal overloads on the 'A', 'B', and 'D' strainer motors. Because this finding is of very lowsafety significance and has been entered into PSEG's corrective action program (evaluations 70058063 and 70059256), this finding is being treated as a non-cited violation consistent with Section VI.A.1 of the NRC Enforcement Policy: NCV 05000354/2006003-01, Corrective Actions to Prevent Repeat Failuresof Service Water Strainer Overloads not Implemented.

1R14 Operator Performance During Non-Routine Evolutions and Events (71111.14)

a. Inspection Scope

(3 samples)The inspectors evaluated personnel performance during two planned evolutions and oneunplanned plant transient. The inspectors observed control room operator performance to verify that operator actions were consistent with station procedures and that allapplicable technical specification action statements were adhered to. The inspectors reviewed trends in applicable plant parameters to verify that plant equipment operatedas designed. The inspectors also reviewed evaluations associated with plant transients to verify PSEG identified causes for the plant transient and implemented appropriate corrective actions. The following evolutions and transients were observed:Intermediate reactor recirculation pump runback during reactor shutdown onApril 6, 2006Reactor recirculation pump motor generator mechanical and electrical stopsetting on June 9, 2006Reactor recirculation loop and shutdown cooling loop vibration test performedJune 16, 2006The Hope Creek plant has operated with a limitation on the maximum recirculation pump speeds that are lower than the plant design of 1680 revolutions per minute (rpm) to minimize system vibration. PSEG instrumented the recirculation system piping and pumps to measure the system vibration at various pump speeds with the objective ofselecting pump operating speeds associated with minimizing system componentvibration and avoiding speeds that produce resonant vibration. PSEG had previouslytaken pipe vibration measurements at various pump speeds below 1500 rpm to correlate pump speed to piping system vibration over about a 2 year period. The plant ran withrecirculation pump speeds that correlate to minimum and acceptable vibration levels.

9EnclosureThe objectives of the reactor recirculation pump test conducted on June 9-16, 2006,included the identification of any higher pump speeds that should be avoided to minimize excess system vibration. The test program included a baseline designanalysis, a large array of direct measurement points, computer based evaluation of the data from the measurements at various pump speeds, and in-plant observations by plant operators to monitor reactor building noise and vibration.Inspection was performed on the testing evolution of the Post 'B' Reactor RecirculationPump Replacement Vibration Evaluation for Core Flows greater than 100 Mlb/hr. On June 8, 2006, the inspectors walked down the test areas and reviewed the test plans with the system engineer responsible for the testing process. On June 9, 2006,inspectors observed the first portion of the test cycle, which was to reduce plant powerto 95% by inserting control rods and then separately increasing each of the two recirculation pumps to reach the test level of flow rate. This was achieved at about 1555 rpm pump speed and included the setting of recirculation pump MG sets mechanical and electrical stops. As this was done for both the 'A' and 'B' pumps, the inspectors observed data vibration measurement and listened for the system sounds inthe vicinity of the two pipe tunnels and the jet pump instrument racks. The inspectorsobserved a meeting in which the testing team debriefed PSEG management on the activities at the conclusion of the first portion of the test cycle.The inspectors observed the pre-job brief and execution of the second phase of the teston June 16, 2006. This part of the test raised pump speeds on the 'A' and 'B' pumps simultaneously from 100 Mlbm/hr to 104.5 Mlbm/hr. Vibration data on the recirculation and shutdown cooling system was gathered at various points during the speed increase. The inspectors observed control room activities as well as walked down portions of the reactor building to determine if abnormal vibrations were present. PSEG reviewed vibration data and determined that no alarm thresholds were reached during the performance of the test.No unusual noise or vibrations were noted by the inspectors during the observed testingand pump speed changes. PSEG had an equipment operator assigned to observe the system conditions of noise and vibration during the test for comparison to normal plantoperation. Discussion with the equipment operator confirmed the inspectorsobservation in regard to noise and vibrations. PSEG engineers analyzed the vibration data collected and concluded that it correlated with field observations in that no abnormal vibrations were present. Documents reviewed are listed in the attachment.

b. Findings

No findings of significance were identified.

10Enclosure1R15Operability Evaluations (71111.15)

a. Inspection Scope

(8 samples)The inspectors reviewed the following eight issues for operability. The inspectorsevaluated the technical adequacy of the associated evaluations to verify operability wasproperly justified and the subject component or system remained available such that nounrecognized increase in risk occurred. The inspectors reviewed the UFSAR and other design basis documents to verify that the system or component remained available toperform its intended function. Interviews were conducted with control room operators and staff engineers. The inspectors walked down plant components and systems toexamine their condition and corroborate the adequacy of PSEG's operabilityassessment. The inspectors also reviewed a sampling of notifications to verify that PSEG was identifying and correcting deficiencies associated with operabilitydeterminations. Documents reviewed are listed in the attachment.*NOTF 20277825, Failure of 'B' control room emergency filtration to produceadequate differential pressure*NOTF 20274462, High vibrations on 'C' emergency diesel generator lube oilkeepwarm pump*NOTF 20278850, 'D' emergency diesel generator load sequencer failure duringsurveillance test*NOTF 20280569, 'A' service water strainer motor trips on thermal overload

• NOTF 20283884, Unexpected gain adjustments on LPRMs following refuelingoutage*NOTF 20286560, Low level observed on wide-range torus water level instrument

• NOTF 20288035, 'B' reactor recirculation pump motor-generator voltageregulator oscillations*NOTF 20280701, Control rod blade 02-138 blistering found during refuelingoutage

b. Findings

No findings of significance were identified.

1R17 Permanent Plant Modifications (71111.17)

a. Inspection Scope

(1 sample)The inspectors reviewed one design change associated with the replacement of the 'B'reactor recirculation pump internals. Specifically, the inspectors reviewed Engineering Change 80076232, Revision 5, which was implemented to provide an upgrade of the 'B' reactor recirculation pump by replacing the pump cover and internals to resolve thermal fatigue cracking concerns. In general, the changes incorporated into the new design were intended to reduce the potential for failed rotating parts. Several of the changes included shaft cracking mitigating features, a welded on impeller and improved maintenance and inspection capabilities.

11EnclosureThe inspectors performed a field walkdown of selected portions of the modification toverify that the installation was in accordance with the design requirements. The inspectors reviewed the change to seal purge flow, along with the elimination of one of the two seal coolers and the jacket cooler from the pump, to ensure the changes had been adequately analyzed and incorporated into system procedures. Due to minorconfiguration changes in the connections of the new pump cover design, the attached piping required minor rerouting. A sample calculation associated with the re-analysis for minor piping modifications was chosen for review to verify that pipe stress remained within acceptable limits. Instrument and Control Calculation, SC-ED-0503, was reviewed to ensure the change in the setpoint for the alarm to the plant computer on lowpump seal cooler flow had an adequate engineering basis. Additionally, the inspectors reviewed the design change determination that the newpump had the same nominal system performance with respect to the original pumpcapabilities. The reactor recirculation pump vibration monitoring procedure wasreviewed to ensure that appropriate revisions were made to incorporate the effects of the modification such as the requirement to determine new critical pump speeds. The proposed revision to Procedure HC.OP-SO.BB-0002(Q), Rev. 59, with field change requests for the modification was reviewed to ensure adequate incorporation of the design changes to the operating procedure. Lastly, PSEG's analyses of recirculation pump startup vibration data was reviewed to evaluate the methodology used indetermining the new pump critical speeds.

b. Findings

No findings of significance were identified.

1R19 Post-Maintenance Testing (71111.19)

a. Inspection Scope

(8 samples)The inspectors reviewed the eight post-maintenance tests listed below to verify thatprocedures and test activities ensured system operability and functional capability. Theinspectors reviewed test procedures to verify the procedure adequately tested the safety functions that may have been affected by the maintenance activity and the acceptance criteria in the procedure were consistent with the UFSAR and other design basis documentation. The inspectors also witnessed the test or reviewed the test data to verify test results adequately demonstrated restoration of the affected safety functions.

Documents reviewed are listed in the attachment.*DCP 80076232, Replacement of 'B' reactor recirculation pump*WO 60058580, Replacement of 'B' station service water strainer body

• WO 60063300, 'B' control room emergency filtration train damper notmaintaining required flow*WO 50078803, Repair of 'C' low pressure coolant injection valve BCHV-F007C*WO 60063505, Repair of 'A' core spray minimum flow check valve BE-V028

• WO 60063201, Station service water pump 'A' packing replacement 12Enclosure*WO 60061918, Repair of 'C' emergency diesel generator lube oil keep-warmpump*WO 30119573, Emergent repair of damaged refueling mast

b. Findings

No findings of significance were identified.

1R20 Refueling and Other Outage Activities (71111.20)

a. Inspection Scope

(1 sample)The inspectors reviewed the schedule and risk assessment documents associated withthe Hope Creek RF13 refueling outage to verify that PSEG appropriately considered risk, industry experience, and previous site-specific problems in developing and implementing an outage plan that maintained a defense-in-depth strategy. Prior to the refueling outage the inspectors reviewed PSEG's outage risk assessment with a regional Senior Risk Analyst to identify risk significant equipment configurations and determine whether planned risk management actions were adequate.The inspectors verified that technical specification cooldown restrictions were adhered toby observing portions of the reactor shutdown and plant cooldown evolutions from the control room. The inspectors walked-down the drywell following the reactor shutdown to identify possible sources of unidentified leakage and observe general equipment condition. Prior to RF13, PSEG postulated through a review of work performed in refueling outage 12 (RF12), observed drywell conditions at the completion of RF12, and radionuclide analysis of drywell sump drains, that most of the measured unidentified leakage during the subsequent operating cycle was likely from the 'C' main steamisolation valve (MSIV) stem-packing. The inspectors confirmed through visual observation that a majority of the unidentified drywell leakage was due to stem packing leakage identified on 'C' MSIV during the drywell walkdown. The inspectors monitoredPSEG's control of the additional outage activities listed below. Documents reviewed for these activities are listed in the attachment.The inspectors verified that PSEG managed the outage risk in accordance with theiroutage plan. Refueling floor activities were observed periodically to observe whether refueling gates and seals were properly installed and determine whether foreign material exclusion boundaries were established around the reactor cavity. The inspectors observed portions of new nuclear fuel receipt, inspection, and placement into new fuel racks. Core offload, reload, and shuffle activities were periodically observed from thecontrol room and refueling bridge to verify that operators controlled fuel movements in accordance with station procedures.The inspectors confirmed, on a sampling basis, that equipment clearance tags werehanged or removed properly and that associated equipment was appropriately configured to support the function of the work activity. Equipment work areas were periodically observed to determine whether foreign material exclusion boundaries were 13Enclosureadequate. During control room walkdowns and observations of plant evolutions theinspectors verified that the instrumentation to measure reactor vessel level and temperature were within the expected range for the operating mode and that they wereconfigured correctly to provide accurate indication. The inspectors periodically verified throughout the outage that electrical power sources were maintained in accordance with technical specification (TS) requirements and consistent with the outage riskassessment. Walkdowns of control room panels, the 500kV switchyard, onsite electrical buses, and EDGs were conducted during risk significant electrical configurations and configuration changes to confirm the equipment alignments met requirements.Risk significant plant evolutions were observed during the outage, including reactorcavity flood up and drain down, installation and removal of main steam line plugs, installation and removal of the fuel pool gates, and residual heat removal systemtransition to shutdown cooling mode of operation to verify adherence to station procedures and outage risk management plans.The inspectors verified through daily plant status activities that the decay heat removalsafety function was maintained with appropriate redundancy as required by TS and consistent with PSEG's outage risk assessment. Contingency plans, procedures and staged equipment for a potential loss of decay heat removal were reviewed and compared to actual plant conditions to verify the effectiveness of mitigation strategies.

During core offload conditions, the inspectors periodically determined whether the fuel pool cooling system was performing in accordance with applicable TS requirements andconsistent with PSEG's risk assessment for the refueling outage. Reactor water inventory controls and contingency plans were reviewed by the inspectors to determine whether they met TS requirements and provided for adequate inventory control.Secondary containment status and procedure controls were reviewed by the inspectorsduring fuel offload and reload activities to verify that TS requirements and procedure requirements were met for secondary containment. Specifically, the inspectors periodically reviewed control room logs for secondary containment penetrations that were open and verified that materials and equipment were staged to seal these penetrations during fuel movement activities as assumed in the licensing basis.The inspectors walked down the containment drywell prior to reactor startup to verify noevidence of RCS leakage and that debris was not left behind from outage work activities that could adversely impact suppression pool suction strainers. The inspectors verified on a sampling basis that technical specifications, license conditions, other requirements, and procedure prerequisites for mode changes were met prior to plant mode changes.

Inspectors reviewed RCS leakage surveillance tests following plant startup to verify RCSintegrity.The inspectors responded to an unexpected reactor vessel level change condition onApril 26, 2006. During reactor reassembly activities, indicated shutdown reactor water level rose by more than 65 inches. Operators ceased main steam line draining activities and investigated the issue. The inspectors discussed the transient with operators, engineers, and plant management to understand the event and assess PSEG's 14Enclosureevaluation of the cause and followup actions. The inspectors reviewed operator actions,station procedures, and plant response to verify proper actions were taken and plant equipment responded as expected. The inspectors reviewed PSEG's apparent cause evaluation of the condition and equipment issues. PSEG determined that proceduraldirection to install blank flanges on RPV head penetrations was the apparent cause of the loss of shutdown level indication.

b. Findings

Introduction:

A Green self-revealing non-cited violation of 10 CFR Part 50, Appendix B,Criterion V, "Instructions, Procedures, and Drawings," was identified when the single source of shutdown reactor water level indication was rendered inaccurate for 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> during reactor vessel reassembly.Description: On April 26, 2006, Hope Creek operators were maintaining reactor waterlevel between 210 and 217 inches, which is just below the reactor pressure vessel (RPV) head flange. Shutdown level recorder LI-R605 and visual observation from the refueling floor were the two sources of indication for reactor water level. At 12:45 am on April 26, 2006, the RPV head was set on the vessel head flange leaving LI-R605 as the single indication of reactor water level. However, all penetrations on the RPV head were isolated via bolted blank flanges (for foreign material exclusion control) creating a non-vented condition for the reactor vessel. At 2:17 am, operators began lowering reactor water level to a new band of 80 to 90 inches to allow for draining of the main steam lines which are at 118 inches. Lowering reactor water level rendered LI-R605 inaccurate, because the RPV was not vented. At 7:33 am, operators began draining themain steam lines to support main steam line isolation valve maintenance. A few minutes later, operators observed that reactor water level on LI-R605 had unexpectedly dropped from 86 to 76 inches and stopped the main steam line draining evolution. At 7:48 am, operators had begun restoring reactor water level to the pre-transient level when indicated reactor water level began to rise rapidly from 83 inches to 145 inches.

While operators were investigating this condition, at 8:15 am, reactor reassembly personnel informed operations control room personnel that they had removed a foreign material exclusion blank flange cover from the RPV head vent flange at approximately 7:45 am.PSEG's RPV disassembly procedure directed the installation of blank flanges on theRPV head penetration connections. PSEG's RPV reassembly and RPV head installation procedures did not contain precautions, cautions or instructions to maintain the RPV head vented following reinstallation of the RPV head on the vessel flange. This was necessary to maintain the reactor water level indication (LI-R605) accurate with a changing level in the reactor vessel.The integrated operations procedure for moving from Refueling to Cold Shutdown alsolacked specific guidance to assure that reactor remained vented to maintain accuracy of the single indication of reactor water level in the shutdown range.

15EnclosureAnalysis: A performance deficiency was identified in that the shutdown reactor waterlevel indication was rendered inaccurate for 7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> because PSEG's integrated plant operations and reactor vessel maintenance procedures did not contain sufficient instructions to ensure that the RPV remained vented during reactor reassembly activities. The finding was more than minor because it was associated with the procedure quality and configuration control attributes of the mitigating systemscornerstone and affected the cornerstone objective to ensure the availability, reliability,and capability of systems that respond to initiating events to prevent undesirableconsequences. In accordance with NRC Inspection Manual Chapter (IMC) 0609,Appendix G, "Shutdown Operations Significance Determination Process," Attachment 1, Checklist 8, the inspectors conducted a Phase 1 SDP screening and determined the finding to be of very low safety significance (Green). The inspectors verified PSEG's shutdown mitigation capability and determined that the finding was not similar to thoserequiring a Phase 2 or Phase 3 analysis. The finding had a cross-cutting aspect in the area of human performance because PSEG did not have adequate procedures to maintain accurate shutdown range reactor water level indication.Enforcement: 10 CFR 50, Appendix B, Criterion V, "Instructions, Procedures, andDrawings," requires, in part, that activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions, procedures or drawings. Contrary to the above, the PSEG maintenance and integratedoperations procedures did not contain sufficient guidance to ensure that the RPVremained vented. As a result, the single indication of reactor water level in the shutdown range was rendered inaccurate while lowering reactor water level on April 26, 2006. Because the finding was of very low safety significance and has been entered into PSEG's corrective action program (notification 20282029) this deficiency is being treated as a non-cited violation consistent with Section VI.A.1 of the NRC EnforcementPolicy: NCV 05000354/2006003-02, Loss of Shutdown Reactor Vessel LevelIndication.

1R22 Surveillance Testing (71111.22)

a. Inspection Scope

(6 Samples)The inspectors witnessed 6 surveillance tests and/or reviewed test data of selectedsurveillance tests listed below to verify that the test met the requirements of the technical specifications, UFSAR, and station procedures. The inspectors also determined whether the testing effectively demonstrated that the systems andcomponents were operationally ready and capable of performing their intended safety functions. Documents reviewed are listed in the attachment.*WO 50081260, 50082713, Residual heat removal system heat exchanger flowmeasurement - 18 Month test*Sample 196492, Reactor coolant system dose equivalent iodine calculation*WO 50080759, Seat leakage testing of residual heat removal valve 1BCV-113 16Enclosure*WO 50082684, 'B' emergency diesel generator LOP/LOCA testing*WO 50082344, Pressure isolation valve inputs into total identified leakage

• WO 50094668, Drywell floor and equipment drain sump monitor channelfunctional test

b. Findings

No findings of significance were identified.

1R23 Temporary Plant Modifications

a. Inspection Scope

(1 sample)A temporary plant modification associated with the reactor building polar crane wasreviewed by the inspectors. The modification bypassed the load-cell interlock during refueling outage activities. The inspectors verified the modification was consistent with the design and licensing bases of the crane and that the performance capability of thecrane was not degraded by the modification. The inspectors reviewed documents to verify PSEG followed their processes for implementing temporary modifications on safety-related equipment. Documents reviewed are listed in the attachment.

b. Findings

No findings of significance were identified.1EP6Drill Evaluation (71114.06)

a. Inspection Scope

(1 sample)Resident inspectors evaluated the conduct of control room operators during simulatedemergency condition scenarios on June 12, 2006, to identify any weaknesses and deficiencies in classification, notification, and protective action recommendation (PAR)development activities. The inspectors observed emergency response operations in the simulated control room to verify that event classification and notifications were done inaccordance with regulations and procedures. The inspectors also attended PSEG's critique of the drill to compare any inspector-observed weakness with those identified byPSEG in order to verify whether PSEG was properly identifying problems. Documents reviewed are listed in the attachment.

b. Findings

No findings of significance were identified.

17Enclosure2.RADIATION SAFETYCornerstone: Occupational Radiation Safety2OS1Access Control to Radiologically Significant Areas (71121.01)

a. Inspection Scope

(7 samples)Based on PSEG's schedule of work activities during the refueling outage (RF13), theinspectors selected three jobs being performed in radiation areas, airborne radioactivity areas, or high radiation areas (<1 R/hr) for observation; reviewed radiological job requirements (radiation work permit [RWP] requirements and work procedure requirements); observed job performance with respect to these requirements; and, determined that radiological conditions in the work area were adequately communicated to workers through briefings and postings. The jobs reviewed were: safety relief valve work; in-service inspection; and, control rod drive replacement.During job performance observations, the inspectors verified the adequacy ofradiological 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.During job performance observations, the inspectors observed radiation workerperformance with respect to stated radiation protection work requirements and determined that they were aware of the significant radiological conditions in theirworkplace, and the RWP controls/limits in place, and that their performance took intoconsideration the level of radiological hazards present.During job performance observations, the inspectors observed radiation protectiontechnician performance with respect to radiation protection work requirements; determined that they were aware of the radiological conditions in their workplace and the RWP controls/limits; and, determined that their performance was consistent with theirtraining and qualifications with respect to the radiological hazards and work activities.The inspectors identified exposure significant work areas within radiation areas, highradiation areas (<1 R/hr), or airborne radioactivity areas in the plant and reviewed associated PSEG controls and surveys of these areas to determine if controls (e.g. surveys, postings, barricades) were acceptable.The inspectors walked down these areas or their perimeters to determine: whetherprescribed RWP, 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 RWPs used to access these and other high radiation areasand identified what work control instructions or control barriers had been specified.

18EnclosureThe inspectors reviewed electronic personal dosimeter alarm set points (both integrateddose and dose rate) for conformity with survey indications and plant policy.In addition, the inspectors reviewed the circumstances surrounding a plant workerreceiving a dose rate alarm while working in a radiation area in the turbine building.

Investigation of the event by PSEG determined that the work area had radiation levels inexcess of 100 millirem per hour measured 30 centimeters from the source of radiation,but was not posted or controlled as a high radiation area.

b. Findings

Introduction.

A Green self-revealing non-cited violation of 10CFR20.1501, "Surveys andMonitoring - General," was identified when a high dose rate alarm was received by a plant worker when working in an improperly controlled high radiation area.Description. On May 7, 2006, during reactor startup operations at the conclusion ofrefueling outage RF13, a plant worker entered the 'A' steam jet air ejector (SJAE) room.

After working in the room for a few minutes, the workers electronic dosimeter began to alarm due to high dose rate. The worker immediately exited the room and notified radiation protection personnel. The electronic dosimeter indicated an exposure of less than 4 millirem, however, the peak dose rate measured by the electronic dosimeter was122 millirem per hour. The alarm setpoint was set for 10 millirem per hour, which isconsistent with entries into some areas in the plant that are not high radiation areas.PSEG performed a prompt investigation of the situation. The investigation into thecause of the alarm revealed that dose rates in the area were in excess of 100 milliremper hour measured 30 centimeters from the source of radiation. PSEG also determinedthat the room was not posted or controlled as a high radiation area. The area wassubsequently posted and controlled as a high radiation area. PSEG concluded thatthere was no formal procedural guidance on when to survey or post this area as a high radiation area.Analysis. The failure to survey an area subject to changing radiological conditions inaccordance with 10 CFR 20.1501 to ensure compliance with the requirements of 10 CFR 20.1201, and to accurately brief workers entering a posted high radiation area (Plant technical specification 6.12) on the radiological conditions was determined to be a performance deficiency and a finding. The finding is more than minor because it is associated with the occupational radiation safety cornerstone attribute of exposure control and affected the cornerstone objective of providing adequate protection of workers from exposure to radiation. Specifically, the radiological conditions present in the 'A' SJAE required posting and control as a high radiation area, in accordance with plant technical specification 6.12.1. Because the performance deficiency involved aworker entering an uncontrolled high radiation area, the finding was evaluated usingInspection Manual Chapter (IMC) 0609, Appendix C, "Occupational Radiation Safety Significance Determination Process." The inspectors determined that the finding was of very low safety significance (Green), because it did not involve (1) ALARA planning and controls, (2) an overexposure, (3) a substantial potential for an overexposure, or (4) an 19Enclosureimpaired ability to assess dose. The performance deficiency had a cross-cutting aspectrelated to human performance associated with it. Specifically, PSEG work controls did not correctly coordinate surveys and postings of the 'A' SJAE rooms following reactor criticality and startup.Enforcement. 10CFR20.1501, "Surveys and Monitoring - General," requires thelicensee to make or cause to be made surveys that are reasonable under the circumstances to evaluate the magnitude and extent of radiation levels to ensurecompliance with 10CFR20.1201 and plant technical specification 6.12.1. Contrary tothis requirement, PSEG failed to survey the 'A' SJAE room on May 3, 2006, when the reactor was made critical. The failure to survey resulted in the 'A' SJAE room becoming an uncontrolled high radiation area that was subsequently accessed by a plant workeron May 7, 2006.Because this finding was of very low safety significance and PSEG entered this findinginto the corrective action program as notification 20283666, this violation is being treated as a Non-Cited Violation (NCV) consistent with Section VI.A of the NRCEnforcement Policy, NUREG-1600: NCV 05000354/2006003-03, Deficiency in AccessControl to Radiological Areas.2OS2ALARA Planning and Controls (71121.02)

a. Inspection Scope

(3 samples)The inspectors obtained from PSEG a list of work activities ranked by actual orestimated exposure that were in progress during the current refueling outage andselected the 3 work activities of highest exposure significance (listed in paragraph 2OS1 above).The inspectors reviewed the as low as is reasonably achievable (ALARA) work activityevaluations, exposure estimates, and exposure mitigation requirements and determined that PSEG had established procedures, engineering and work controls, based on sound radiation protection principles, to achieve occupational exposures that are ALARA. The inspectors compared the results achieved (dose rate reductions, person-rem used)with the intended dose established in PSEG's ALARA planning for these work activities.

b. Findings

No findings of significance were identified.

20Enclosure2OS3Radiation Monitoring Instrumentation and Protective Equipment (71121.03)

a. Inspection Scope

(1 sample)The inspectors verified the calibration expiration date and validated that the sourceresponse check was current on radiation detection instruments staged for use.

b. Findings

No findings of significance were identified.4.OTHER ACTIVITIES4OA1Performance Indicator Verification (71151)

g. Inspection Scope

(5 samples)Cornerstone: Initiating EventsThe inspectors reviewed PSEG's program to gather, evaluate and report information onthe following performance indicators (PIs). The inspectors used the guidance contained in NEI 99-02, "Regulatory Assessment Performance Indicator Guideline," Revision 3, to assess the accuracy of PSEG's collection and reporting of PI data. The documents reviewed by the inspectors are listed in the attachment.*Unplanned SCRAMS per 7,000 Critical Hours*Unplanned SCRAMS with Loss of Normal Heat Removal

• Unplanned Power Changes per 7,000 Critical HoursThe inspectors verified the accuracy and completeness of reported manual andautomatic unplanned scrams during the period of October 1, 2004 through March 31, 2006 for the "Unplanned Scrams per 7,000 Critical Hours" PI.The inspectors reviewed and verified PSEG's basis for including or excluding anunplanned reactor scrams for the "Unplanned Scrams with Loss of Normal Heat Removal" PI during the period of October 1, 2004 through March 31, 2006.The inspectors verified the accuracy and completeness of reported transients thatresulted in unplanned changes and fluctuations in reactor power of greater than 20 percent power for the "Unplanned Power Changes per 7,000 Critical Hours" PI during the period of October 1, 2004 through March 31, 2006.Cornerstone: Barrier Integrity

• Reactor Coolant System Specific Activity 21Enclosure*Reactor Coolant System LeakageThe inspectors verified the methods used to calculate the reactor coolant systemspecific activity PI and reviewed the accuracy of the PI data submitted during for the period July 1, 2004 through March 31, 2006.The inspectors verified the methods used to calculate the reactor coolant systemleakage PI. The inspectors verified the accuracy of PI data submitted for the period July 1, 2004 through March 31, 2006.

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, the inspectors performed a daily screening of all items entered into PSEG's corrective action program to identify repetitive equipment failures or specific human performance issues for additional review. This was accomplished by reviewing the description of each new notification and attending management review committee meetings. Risk significant issues were reviewed further by inspectors through Plant Status or were selected as a sample for inspection under Reactor Safety inspection attachments..2Semi-Annual Review to Identify Trends

a. Inspection Scope

(1 sample)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. The review also included issues documented outside the normal CAP in system health reports, corrective maintenancework orders, component status reports, site monthly meeting reports and maintenance rule assessments. The inspectors' review nominally considered the six-month period of December 1, 2005, through June 1, 2006, although some examples expanded beyond those dates when the scope of the trend warranted. The inspectors specifically trended events affecting reactivity management reactivity events as defined in PSEG procedure NC.NA-AP.ZZ-0089. The inspectors compared and contrasted their results with the results contained in PSEG's latest monthly Reactivity Management Performance Indicator and station reactivity management procedure. Corrective actions associated with a sample of the issues identified in PSEG's performance indicator were reviewed for adequacy. Documents reviewed are listed in the attachment.

b.Assessment and ObservationsNo findings of significance were identified.PSEG's Reactivity Management performance indicator identified three reactivitymanagement challenges which correlated with the issues identified by the inspectors through plant status and CAP reviews..3Annual Sample: Station Service Water Deicing Line Degradation

a. Inspection Scope

The inspectors reviewed PSEG's actions to resolve repetitive degraded conditionsidentified on the deicing system for the service water intake structure. Specifically,flooding of a number of underground valve pits containing motor-operated valves used to operate the non-safety related deicing system was identified a number of times in theCAP. This issue was selected due to its potential to impact the operability of risksignificant equipment, including the potential for common cause failure of all four trains of service water due to frazil ice buildup on the service water intake trash racks andtraveling screens. The deicing system is not identified as a safety-related system; however, it is describedin the UFSAR and used in station emergency procedures to deliver warming water to the service water intake to mitigate both frazil ice buildup and potential blockage of the service water trash racks and traveling screens.The deicing system draws water from either the circulating water system at the outlet ofthe main condenser or from the service water system discharge header servicing thecooling tower basin. Both deicing system warm water supplies are normally isolated bya single motor-operated valve in each supply header. The valves are normally controlled remotely from the control room when needed, but have the capability of beingoperated manually inside the valve pits.The inspectors reviewed notifications, evaluations, design documentation andinterviewed cognizant engineers and operators to determine if the system was capableof performing its design function. The inspectors also reviewed PSEG's plans to address and correct the degraded conditions.

b. Findings and Observations

No findings of significance were identified.

The inspectors found that PSEG generally entered degraded conditions into thecorrective action program. PSEG had entered degraded conditions associated with the flooded valve pits and the potential for the valves in the valve pit to fail a number of times over several years. However, PSEG did not thoroughly evaluate the impact of the degraded conditions on the ability of the deicing system to perform its design function.

23EnclosureAlso, PSEG did not effect corrective actions or maintenance activities to repair knowndegraded conditions of the motor operated valves described above. Additionally, PSEG determined through a review of maintenance history that the valves were tagged out inthe closed position from at least February 1992 until December 2005.Following questioning from inspectors, PSEG evaluated the condition of the servicewater deicing system. PSEG's evaluation included corrective actions that developed adeicing system restoration plan to improve the material condition of the system andsystematically inspect and test system components prior to the onset of cold weather in2006. Improvements include sealing valve pit penetrations, repair or installation of new sump pumps in the valve pits, repair electrical supplies to valve pit motor operated valves, repair or replacement of trash racks and support components, and replacementof the deicing header and downcomer piping.The inspectors determined that PSEG had the ability to place the system in servicemanually, if required, at all times. The inspectors also concluded that the corrective actions developed by PSEG were appropriate to the extent it would return the system toa fully functional condition and adequately address known deficiencies..4Safety 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.On May 10, 2006, the inspectors conducted a sampling review of PSEG's SCWEmetrics, or 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. This was an improvement from the fourth quarter 2005 results of twenty-one green PIs and eight red PIs.

24Enclosure4OA5Other Activities.1Institute of Nuclear Power Operations (INPO) Plant Assessment Report Review

a. Inspection Scope

The inspectors reviewed the final report for the INPO plant assessment of the HopeCreek Generating Station conducted in March 2006. The inspectors reviewed the reportto ensure that issues identified were consistent with the NRC assessment of PSEG'sperformance and to verify if any significant safety issues were identified that required further NRC review.

b. Findings

No findings of significance were identified..2Implementation 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 operation 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.The information gathered while completing this TI was forwarded to the Office ofNuclear Reactor Regulation (NRR) for further review and evaluation on April 3, 2006. The NRR review was completed with no further action required with respect toTI 2515/165.

b. Findings

No findings of significance were identified..3(Closed) URI 2006002-02, Additional NRC Review Required to Further Evaluate RHRHeat Exchanger (HX) Flow Testing MethodologyURI 2006002-02 was opened in NRC Inspection Report 05000354/2006002 Section1R07.2 because inspectors identified issues with the methodology PSEG used to perform residual heat removal (RHR) HX flow testing. Specifically, the inspectorsidentified that: (1) the 18-month ST did not provide direction on how to calculate RHR HX and bypass flows; (2) the 18-month ST did not provide direction on placement of ultrasonic flow instruments, calibration of these instruments, or required accuracy and range of these instruments; (3) PSEG used temporarily installed measuring and test 25Enclosureequipment having a minimum accuracy of +/- 0.5% for the RHR combined (HX & bypass)flow rate during the quarterly RHR pump ST, but used the less accurate installed plantinstrumentation for the 18 month ST; (4) PSEG did not use the recorded ultrasonic flowinstrument data on the RHR HX outlet lines in their calculation of HX flow (this temporary instrument was specifically installed for this flow test); and (5) the 35 sets of recorded data for each HX appeared erratic. The inspectors reviewed notifications 20272419, 20288825, and evaluation 70054151that documents PSEG's response to the above issues. The inspectors also reviewed the results of the 'A' and 'B' RHR HX flow testing surveillance tests during the refuelingoutage as listed in Section 1R22 of this report. As a corrective action from evaluation 70054151, PSEG changed the surveillance test procedure and testing methodologyprior to the refueling outage to improve the direction provided to calculate RHR HXbypass flow and place the ultrasonic detector at a fixed location on the HX discharge line to ensure accurate and consistent test results. The ultrasonic measurement device that measured bypass flow previously was removed altogether to eliminate large measurement fluctuations due to low flow conditions in the bypass line. The test results achieved during the refueling outage demonstrated that the RHR HXs were operable.The inspectors determined that the procedure and methodology changes made byPSEG addressed the issues identified in URI 2006002-02 satisfactorily. This URI is closed.4OA6Meetings, Including ExitNRC/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 June 6, 2006, the inspectors presented their overall findings tomembers of PSEG management led by Messrs. Barnes and Massaro. None of the information reviewed by the inspectors was considered proprietary. ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee personnel

G. Barnes, Site Vice President

M. Massaro, Hope Creek Plant Manager

H. Hanson, Operations Director

Paul Davison, Engineering Director

Mark Pfizenmeier, Senior Manager Plant Engineering

Joan Glunt, Work Management Director

M. Davis, Radiation Protection Supervisor

T. O'Hare, Radiation Protection Supervisor

B. Sebastian, Radiation Protection Manager

J. Barstow, Regulatory Affairs/Compliance Engineer

J. Williams, Hope Creek Engineering

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened/Closed05000354/2006003-01NCVCorrective Actions to Prevent Repeat Failures ofService Water Strainer Overloads not Implemented

(Section 1R13)05000354/2006003-02NCVLoss of Shutdown Reactor Pressure Vessel LevelIndication (Section 1R20)05000354/2006003-03NCVDeficiency in Access Control to Radiological Areas(Section 2OS1)

Closed

05000354/FIN-2006002-02URIAdditional NRC Review Required to FurtherEvaluate RHR HX Flow Testing Methodology(Section 4OA5.3)

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:Hope Creek Generating Station (HCGS) Updated Final Safety Analysis ReportTechnical Specification Action Statement Log (HC.OP-AP.ZZ-0108)

HCGS NCO Narrative Logs

HCGS Plant Status Reports Weekly Reactor Engineering Guidance to Hope Creek Operations Hope Creek Operations Night Orders and Temporary Standing Orders

Section 1R01: Adverse Weather ProtectionProceduresSH.OP-DG.ZZ-0011, Rev. 4, Station Seasonal Readiness GuideWC-AA-107, Rev. 2, Seasonal Readiness

NC.OP-DG.ZZ-0002, Rev. 6, Severe Weather Guide

HC.OP-AB.COOL-0001, Rev. 7, Station Service Water

HC.OP-AB.HVAC-0001, Rev. 3, HVACCorrective Action Notifications202460722027291620276127

Orders7005538970054394

Other Documents2006 Hope Creek Summer Readiness MatrixService Water SHIP Action Plan for Red and Yellow Systems dated February 3, 2006 and February 28, 2006

Chilled Water SHIP Action Plan for Red and Yellow Systems

Section 1R04: Equipment AlignmentProceduresHC.OP-SO.BC-0001, Rev 41, Residual Heat Removal System OperationHC.OP-SO.BC-0002, Rev 18, Decay Heat Removal Operation

HC.OP-ST.BJ-0001, Rev 11, HPCI System Piping and Flow Path Verification - Monthly

HC.OP-SO.BJ-0001, Rev 32, High Pressure Coolant Injection System Operation

HC.OP-SO.EA-0001, Rev. 28, Service Water System OperationDrawingsM-55-1, Rev. 24, High Pressure Coolant InjectionM-56-1, Rev. 16, HPCI Pump Turbine

A-3AttachmentCorrective Action Notifications20264759Other DocumentsEC-0074, Rev. 11, HCGS Decay Heat-up Rates and Curves

Section 1R05: Fire ProtectionProceduresHope Creek Pre-Fire Plan

FRH-II-413, Rev. 3, HPCI Pump & Turbine Room, RHR Pump &Heat Exchanger Rooms, Elevation 54' Hope Creek Pre-Fire Plan

FRH-II-412, Rev.3, RCIC Pump & Turbine Room, RHR Pump & HeatExchanger Rooms & Electrical Equipment Room, Elevation 54' Hope Creek Pre-Fire Plan

FRH-II-151, Rev. 3, Turbine Building Elevation 137' Hope Creek Pre-Fire Plan

FRH-II-434, Rev. 3, Motor Control Center Area Elevation 102' Hope Creek Pre-Fire Plan

FRH-II-461, Rev. 3, FRVS Rooms, MCC Area, Recombiner Areas, Spent Fuel Pool & Gamma Scan Detector Area Hope Creek Pre-Fire Plan

FRH-II-351, Rev. 6, Service and Radwaste Area Elevation 137' Hope Creek Pre-Fire Plan

FRH-II-442, Rev. 4, Inert Gases Compressor Rooms, FRVS Re-

Circulating Unit Area, Steam Vent & Equipment Area Elevation 132' Hope Creek Pre-Fire Plan

FRH-II-551, Rev. 6, Battery Rooms & Cable Chases Elevation 146' Hope Creek Pre-Fire Plan

FRH-II-532, Rev. 5, Lower Control Equipment Room, Elevation 102'

HC.FP-SV.ZZ-0026, Rev. 4, Flood and Fire Barrier Penetration Seal Inspection

HC.FP-AP.ZZ-0004, Rev. 9, Actions for Inoperable Fire Protection - Hope Creek Station

HC.FP-AP.ZZ-0025, Rev. 4, Precautions Against FireCorrective Action Notifications202692582027816620248868

Orders50069540

Other DocumentsHope Creek Hourly Fire Watch Patrol Inspection Log dated May 24, 2006

Section 1R06: Flood Protection MeasuresProceduresHC.OP-AB.MISC-0001 Rev. 6, Acts of NatureNC.OP-DG.ZZ-0002 Rev. 6, Severe Weather GuideDrawingsA-0203-0, Rev. 11, Hope Creek Generating Station, General Plant Floor Plan, Level 3 - Elevation 102'-0"

A-4AttachmentCorrective Action Notifications20287013202682302022738820212131Orders70042746

Other DocumentsUFSAR Section 2.4, Hydrologic EngineeringIndividual Plant Examination for External Events (IPEEE) sections 5.3.4 and 5.5

Technical Specifications 3/4.7.3, Flood Protection Measures

Section 1R07: Heat Sink PerformanceProceduresHC.SE-PR.EG-0001, Rev. 5, Safety and Auxiliary Cooling System Annual Biofouling MonitoringNC.MCT-DG.ZZ-0001, Rev. 1, Balance of Plant Heat Exchanger Condition Assessment

ProgramDrawingsM-II-I Sheet 1, Rev 17, Safety Auxiliaries Cooling Reactor BuildingCorrective Action Notifications20050728200606072005122120050702

Other DocumentsChemistry Measurements of SACS from June 1, 2005 to June 20, 2006Information Notice 89-71, Diversion of the Residual Heat Removal Pump Seal Cooling Water Flow During Recirculation Operation Following a Loss-of-Coolant Accident Calculation Number

EG-0020(Q), Rev 8

Calculation Number

SC-EG-0159, Rev 1

Calculation Number

EG-0011(Q), Rev 1

Design, Installation and Test Specification for Safety and Turbine Auxiliaries Cooling System forthe Hope Creek Generating Station

PN1-E11-C002-0051, Vendor Information for the Residual Heat Removal System Pump

EPRI

NP-7552, Heat Exchanger Performance Monitoring Guidelines

DE-CB.EG-0054, Rev. 2, Configuration Baseline Documentation for Safety and TurbineAuxiliaries Cooling SystemSection 1R08: Inservice Inspection ActivitiesProceduresSH.RA-IS.ZZ-0116, Revision 10, 4/16/04; Inservice Inspection Visual Examination of NuclearClass I Bolting, Nuclear Class 3 Integral Welded Attachments, Nuclear Class I Pump/Valve Internal Surfaces, Nuclear Class I External Pump Casing Weld Surfaces Hope Creek Nuclear Generating Station, Inservice Inspection Program Second 10 Year Interval

IWE Long Term Plan, Revision 0, January 2000

HC.CH-SA.ZZ-0004, Revision 1, 2/86/06; Determination Of Reactor Percent Moisture Carryover

A-5AttachmentDrawingsL002040, Revision C, Pump Sectional Type DVSS2F-1435, Revision 0, Outline Reactor Recirculating Pump

2F-1437, Revision H, Outline Reactor Recirculating Pump

1-P-ED-220, Revision 2; Engineered Small Piping/Drywell Building; RACS Water From Pump

BP-201 Internal Heat Exchanger

1-P-ED-221, Revision 2; Engineered Small Piping/Drywell Building; RACS Water From Pump

BP-201 Internal Heat ExchangerCalculationsH-1-ZZXX-SEE-0166-0, 3/12/87; NRC IE Information Notice No. 86-99 Degradation of SteelContainmentsCorrective Action Notifications2021115220213688

209438

214041

230960

2600382025524520213925

208591

20141931

211910

201759062021089320211135

212346

212271

2116382021231120212272

212353

20175906

2154702025158820215541

207276

280110

2808612028076020280742

280574

280904

212346Design Change PackagesDCP

80089168, Revision 0, 4/17/06; Jet Pump Slip Joint Clamp RepairDCP

80040594, 12/16/04;

HIBB-10-S-201 piping, ASME III, Class 2 Pressure Boundary RepairDCP

80076232, ANSI B31.1 Repair; modify RACS cooling water lines to new recirc pump coolerNDT Examination ReportsData Sheet 50082844/101212; Recirc Pump B Flange Surface; 1-BP-201-PISData Sheet 50082874/160010;

VT-3 B Recirc Pump Data Sheet

105521, Liquid Penetrant Exam, Component ID: 1-BB-1CCA-225-1, instrument lineto nozzle Data Sheet

105522, Liquid Penetrant Exam, Component ID: 1-BB-1CCA-223-1, instrument lineto nozzle Data Sheet

105732, Liquid Penetrant Exam, Component ID: 1-BB-1CCA-220-1, instrument lineto nozzle Data Sheet

105731, Liquid Penetrant Exam, Component ID: 1-BB-1CCA-218-1, instrument lineto nozzle Data Sheet

105523, Liquid Penetrant Exam, Component ID: 1-BB-1CCA-319-FW1, instrument line to nozzle Data Sheet

250150, Liquid Penetrant Exam, Component ID: 1-CP-206-CSP-W4, Pump Casing Weld Data Sheet

107565, Liquid Penetrant Exam, Component ID: 1-BB-12VCA-014E-5, Pipe To Safe End Data Sheet

100145, Ultrasonic Exam, Component ID:

RPV1-W20,Head to Flange Data Sheet

100690, Ultrasonic Exam, Component ID:

RPV1-N2KSE,Weld Overlay

A-6AttachmentData Sheet

101212,

VT-1 Visual Exam of Nuclear Class I Bolting, order

50082874, BRecirculation Pump Drywell; Component ID:

RCPB-1BLT,(Flange 16)

Data Sheet

160010,

VT-3 Visual Exam of Nuclear Class I Pump/Valve Internal Surfaces;

Component ID:

BP-201-PIS, Pump Casing, 'B' Recirc Pump

INR HCR13-IVVI-06-03 Steam Dryer

INR HCR13-IVVI-06-04, Revision 1. Steam Dryer Partition Plate

INR HCR13-IVVI-06-04, Steam Dryer Partition Plate

INR HCR13-IVVI-06-05, Steam Dryer Ring

INR HCR13-IVVI-06-06, Steam Dryer Lifting Assembly

INR HCR13-IVVI-06-07 Steam Dryer Lower Guide

INR HCR13-IVVI-06-01 Jet Pump

WD-1 Wedge Rev. 1

INR HCR13-IVVI-06-02 Jet Pump

AS-1 Gap Measurement

IWE Visual Inspection Report #830900, Component ID PEN-HC-J9

IWE Visual Inspection Report #830400, Component ID PEN-HC-J4

IWE Visual Inspection Report #827500, Component ID PEN-HC-P23

IWE Visual Inspection Report #835400, Component ID PEN-HC-J1351

IWE Visual Inspection Report #830600, Component ID PEN-HC-J6

IWE Visual Inspection Report #827000, Component ID PEN-HC-P18

IWE Visual Inspection Report #829500, Component ID PEN-HC-P39

IWE Visual Inspection Report #830300, Component ID PEN-HC-J3

IWE Visual Inspection Report #829510, Component ID PEN-HC-P13

IWE Visual Inspection Report #835700, Component ID PEN-HC-J1354

IWE Visual Inspection Report #827310, Component ID

BLT-HC-P21 Flange Bolting

IWE Visual Inspection Report #827300, Component ID

PEN-HC-P21 Blind Flange

IWE Visual Inspection Report #830700, Component ID PEN-HC-J7

IWE Visual Inspection Report #822200, Component ID PEN-HC-W102C

IWE Visual Inspection Report #822500, Component ID PEN-HC-W103B

IWE Visual Inspection Report #823800, Component ID PEN-HC-W105C

IWE Visual Inspection Report #829700, Component ID

HCH-HC-C2 Equipment HatchIWE Visual Inspection Report #829710, Component ID

HCH-HC-C2 Equipment Hatch BoltingIWE Visual Inspection Report #829720, Component ID

ALK-HC-C2 Personnel Airlock

IWE Visual Inspection Report #829730, Component ID

BLT-HC-C2 Pers. Airlock Bolting

IWE Visual Inspection Report #821200, Component ID PEN-HC-W100C

IWE Visual Inspection Report #824600, Component ID PEN-HC-W106C

IWE Visual Inspection Report #829800, Component ID

HCH-HC-C3 CRD HatchIWE Visual Inspection Report #829810, Component ID

BLT-HC-C3 CRD Hatch BoltingIWE Visual Inspection Report #822000, Component ID PEN-HC-W102A

IWE Visual Inspection Report #821000, Component ID PEN-HC-W100A6C

IWE Visual Inspection Report #823500, Component ID PEN-HC-W104K

IWE Visual Inspection Report #824000, Component ID PEN-HC-W105E

IWE Visual Inspection Report #823600, Component ID PEN-HC-W105A

IWE Visual Inspection Report #824100, Component ID PEN-HC-W105F

IWE Visual Inspection Report #824400, Component ID PEN-HC-W106A

IWE Visual Inspection Report #823400, Component ID PEN-HC-W104J

IWE Visual Inspection Report #823300, Component ID PEN-HC-W104H

IWE Visual Inspection Report #826200, Component ID PEN-HC-P7

IWE Visual Inspection Report #823200, Component ID

PEN-HC-W104G

A-7AttachmentIWE Visual Inspection Report #823100, Component ID

PEN-HC-W104FIWE Visual Inspection Report #828100, Component ID PEN-HC-P28A

IWE Visual Inspection Report #834200, Component ID PEN-HC-J42

IWE Visual Inspection Report #825800, Component ID PEN-HC-P6A

IWE Visual Inspection Report #837100, Component ID

PEN-HC-P35A CRD InsertIWE Visual Inspection Report #837500, Component ID

PEN-HC-P36A CRD WithdrawIWE Visual Inspection Report #834300, Component ID PEN-HC-J43

IWE Visual Inspection Report #834100, Component ID PEN-HC-J41

IWE Visual Inspection Report #827400, Component ID PEN-HC-P22

IWE Visual Inspection Report #828300, Component ID PEN-HC-P29

IWE Visual Inspection Report #825400, Component ID PEN-HC-P4A

IWE Visual Inspection Report #826300, Component ID PEN-HC-P8A

IWE Visual Inspection Report #828400, Component ID PEN-HC-P30

IWE Visual Inspection Report #826400, Component ID PEN-HC-P8B

IWE Visual Inspection Report #825600, Component ID PEN-HC-P5A

IWE Visual Inspection Report #821400, Component ID PEN-HC-W101A

IWE Visual Inspection Report #834900, Component ID PEN-HC-J49

IWE Visual Inspection Report #834700, Component ID PEN-HC-J47

IWE Visual Inspection Report #825900, Component ID PEN-HC-P6B

IWE Visual Inspection Report #821500, Component ID PEN-HC-P101B

IWE Visual Inspection Report #837200, Component ID

PEN-HC-P35B CRD InsertIWE Visual Inspection Report #837600, Component ID

PEN-HC-P36B CRD WithdrawIWE Visual Inspection Report #821600, Component ID PEN-HC-W101C

IWE Visual Inspection Report #828500, Component ID PEN-HC-P31

IWE Visual Inspection Report #834800, Component ID PEN-HC-J48

IWE Visual Inspection Report #826700, Component ID PEN-HC-P11

IWE Visual Inspection Report #820100, Component ID

VSL-HC-Drywell Head Internal

IWE Visual Inspection Report #820200, Component ID

VSL-HC-Drywell Head External

IWE Visual Inspection Report #820300, Component ID

BLT-HC-Drywell Head Bolting

IWE Visual Inspection Report #829900, Component ID

HCH-HC-C5 Drywell Head HatchIWE Visual Inspection Report #829910, Component ID

BLT-HC-C5 DW Head Hatch Bltg

IWE Visual Inspection Report #825300, Component ID PEN-HC-P3

IWE Visual Inspection Report #837300, Component ID

PEN-HC-P35C CRD InsertIWE Visual Inspection Report #837700, Component ID

PEN-HC-P36C CRD WithdrawIWE Visual Inspection Report #834600, Component ID PEN-HC-J46

IWE Visual Inspection Report #826000, Component ID PEN-HC-P6C

IWE Visual Inspection Report #829300, Component ID PEN-HC-P38A

IWE Visual Inspection Report #834500, Component ID PEN-HC-J45

IWE Visual Inspection Report #835000, Component ID PEN-HC-J50

IWE Visual Inspection Report #828000, Component ID PEN-HC-P27

IWE Visual Inspection Report #829400, Component ID PEN-HC-P38B

IWE Visual Inspection Report #827700, Component ID PEN-HC-P24B

IWE Visual Inspection Report #828200, Component ID PEN-HC-P28B

IWE Visual Inspection Report #835200, Component ID PEN-HC-J52

IWE Visual Inspection Report #825700, Component ID PEN-HC-P5B

IWE Visual Inspection Report #835100, Component ID PEN-HC-J51

IWE Visual Inspection Report #821700, Component ID

PEN-HC-W101D

A-8AttachmentIWE Visual Inspection Report #834400, Component ID

PEN-HC-J44IWE Visual Inspection Report #825500, Component ID PEN-HC-P4B

IWE Visual Inspection Report #837400, Component ID

PEN-HC-P35D CRD InsertIWE Visual Inspection Report #837800, Component ID

PEN-HC-P36D CRD WithdrawIWE Visual Inspection Report #821800, Component ID PEN-HC-W101E

IWE Visual Inspection Report #826100, Component ID PEN-HC-P6D

IWE Visual Inspection Report #821900, Component ID PEN-HC-W101F

IWE Visual Inspection Report #826800, Component ID PEN-HC-P12

IWE Visual Inspection Report #829520, Component ID PEN-HC-P15

IWE Visual Inspection Report #824700, Component ID PEN-HC-P1A

IWE Visual Inspection Report #825100, Component ID PEN-HC-P2A

IWE Visual Inspection Report #824800, Component ID PEN-HC-P1B

IWE Visual Inspection Report #824900, Component ID PEN-HC-P1C

IWE Visual Inspection Report #825200, Component ID PEN-HC-P2B

IWE Visual Inspection Report #825000, Component ID PEN-HC-P1D

IWE Visual Inspection Report #829600, Component ID

PEN-HC-C1 Equipment Hatch

IWE Visual Inspection Report #829610, Component ID

BLT-HC-C1 Equip Hatch Bltg

IWE Visual Inspection Report #821100, Component ID PEN-HC-W100B

IWE Visual Inspection Report #823700, Component ID PEN-HC-W105B

IWE Visual Inspection Report #822100, Component ID PEN-HC-W102B

IWE Visual Inspection Report #824200, Component ID PEN-HC-W105G

IWE Visual Inspection Report #824300, Component ID

PEN-HC-W105HQualification RecordsNDE Certificate of Qualification, Michael Hicks, 4/5/06;

VT-1, 2, 3 Level IIEngineering EvaluationsSteam Dryer Indications, NUCR

70056479, Operation 10MiscellaneousNRC Confirmatory Action Letter No. 1-05-001, 1/11/05PSEG Ltr.

LR-N05-0017, 1/9/05; PSEG Actions In Response To NRC Concerns Regarding 'B'Reactor Recirculation Pump Hope Creek Generating Station Docket No. 50-354

PSEG Ltr.

LR-N06-0053; Actions To Close CAL 1-05-001 'B' Reactor Recirculation Pump Hope Creek Generating Station Facility Operating License No.

NPF-57, Docket No. 50-354BWR-VIP-139; BWR Vessel and Internals Project Steam Dryer Inspection and Flaw Evaluation Guidelines, EPRI 2005, Prepared by GE Nuclear

GE

SIL 644, Revision 1

VTD-327395(001);

GENE-0000-0034-9350-R1, Revision 1, 12/04; Evaluation of Steam Dryer Indications Hope Creek Generating Station

VTD-328444(001);

GENE-0000-0046-8137-R0,

DRF-0000-0043-9289, Revision 0, 12/08;

Steam Dryer Support Ring Crack Growth Rate Prediction For Hope Creek Generating Station.

VTD-327419(1); Lisega Calculation

ER-VR04-0752, 12/23/04

VTD-327693(001);

GENE-0000-0036-1606, Revision 0; Technical Safety Evaluation, Reactor Recirculation Pump 4th Generation Modification, Hope Creek Generating Station, 4/14/05

A-9Attachment

Section 1R11: Licensed Operator Requalification ProgramProceduresHC.OP-AB.CONT-0002, Primary Containment, Rev 2HC.OP-EO.ZZ-0101, Reactor Pressure Vessel Control, Rev 10

NC.EP-EP.ZZ-0404, Protective Action Recommendations (PARS) Upgrades, Rev 2

HC.OP-AB.COMP-0002, Primary Containment Instrument Gas, Rev 4Corrective Action Notifications2028743820287762

Other DocumentsSimulator Scenario Guide

SG-263, Reactor Recirc Pump Trip / RWCU Leak / PCIG Leak /Failure of RPS, Rev 3

NC.TQ-WB.ZZ-0003, Attachment 1, Crew Competency Summary Sheet, Rev 6

NC.EP-DG.ZZ-0001, Form 1, DEP Observation Checklist, Rev 6

NC.TQ-AS.ZZ-1003, Attachment 1, Management Observation of Training (MOT) Form, Rev 3

Section 1R12: Maintenance EffectivenessProceduresHC.OP-SO.PN-0001, 120

VAC Electrical Distribution, Rev. 16HC.MD-CM.PN-0001, 20 KVA Inverter Troubleshooting and Repair, Rev. 9

HC.OP-AP.ZZ-0108, Operability Assessment and Equipment Control Program, Rev. 18HC.OP-AB.ZZ-0136, Loss of 120 VAC Inverter, Rev. 9

HC.OP-AP.ZZ-0031, Control of Alarm Bypass, Rev. 0DrawingsE-0006-1, 4.16 KV Class 1E Power System, Rev. 11E-0012-1, 120V AC Instrumentation & Misc. Systems, Rev. 7

E-0018-1, 480 Volt Class 1E Unit Substa. 10B410, 10B420, 10B430, 10B440, 10B450, 10B460,10B470, 10B480, Rev. 16

E-0019-1, 480 Volt MCC Tabulation Class 1E - Aux Bldg - D/G Area 10B411, 10B421, 10B431,

10B441, Rev. 12

E-0020-1, 480 Volt MCC Tabulation Class 1E - Aux Bldg - D/G Area 10B451, 10B461, 10B471,

10B481 Rev. 14Corrective Action Notifications2028168220283474

2779902027876020278666

2878202027446220210237

2556442027243420276416

2771832027734420279751

2822412028447520284765Orders6006268390002327600619187005610450081764600610446006178970042626700544107005556670056832

A-10AttachmentOther DocumentsNRC Regulatory Guide 1.160, Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, Revision 2

NUMARC 93-01, Industry Guideline For Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, Revision 2

Plant Health Committee System Presentation for Emergency Diesel Generators - 1Q 2006Emergency Diesel Generator System Health Report 1Q 2006

Emergency Diesel Generator Maintenance Rule Reliability and Unavailability logsOTDM

HC-2006-0009 Emergency Diesel Generator (EDG) Lube Oil Keep Warm Pump

Section 1R13: Maintenance Risk Assessments and Emergent Work ControlProceduresHC.OP-AP.ZZ-0108, Rev. 0, On-Line Risk AssessmentHC.FP-ST.KC-0009, Rev. 14, Diesel Driven Fire Pump Operability TestHC.MD-PM.KC-0001, Rev. 5, Diesel Fire Pump And Diesel Engine P.M.

HC.MD-CM.EA-0003, Rev. 25, Service Water Strainer Overhaul & Repair

HC.MD-CM.EA-0003, Rev. 27, Service Water Strainer Overhaul & Repair

HC.MD-PM.EA-0001, Rev. 18, Service Water Strainer - Clean and Inspect

HC.MD-PM.EA-0001, Rev. 19, Service Water Strainer - Clean and Inspect

HC.MD-PM.EA-0001, Rev. 20, Service Water Strainer - Clean and Inspect

HC.MD-PM.EA-0001, Rev. 21, Service Water Strainer - Clean and Inspect

NC.WM-AP.ZZ-0000, Rev. 10, Notification Process

NC.WM-AP.ZZ-0000, Rev. 13, Notification Process

NC.WM-AP.ZZ-0002, Rev. 8, Corrective Action Process

NC.WM-AP.ZZ-0002, Rev. 9, Corrective Action Process

NC.CC-AP.ZZ-0080, Rev. 19, Engineering Change Process

NC.CC-AP.ZZ-0081, Rev. 8, Engineering Change Implementation and Test Process

HC.OP-AP.ZZ-0108, Rev. 23, Operability Assessment and Equipment Control ProgramHC.OP-AP.ZZ-0108, Rev. 24, Operability Assessment and Equipment Control ProgramHC.OP-AP.ZZ-0108, Rev. 25, Operability Assessment and Equipment Control ProgramLS-AA-120, Rev. 5, Issue Identification and Screening Process

HC.OP-AR.ZZ-0001, Rev. 16, Overhead Annunciator Window Box A1

HC.OP-AP.ZZ-0109, Rev. 14, Equipment Operational Control

HC.OP-AB.COOL-0001, Rev. 4, Station Service Water

HC.OP-AB.COOL-0001, Rev. 8, Station Service WaterCorrective Action Notifications2028750320178691

201789532020481420204953

2063352020647420212968

2131742028056920280959

2818132028344820284983

2849842028636220289628Orders3013995430059866

30097091

30124011

301308026003873060043083

60048403

60050019

600501236006226860062304

60062305

70037109

700371817004161470041902

70043287

70056583

700567297005711770058063

80032450

80068087

800766408007676380079630

80089544

A-11AttachmentOther DocumentsSE.MR.HC.02, System Function Level Maintenance Rule VS Risk ReferenceHCGS PSA Risk Evaluation Forms for Work Week Nos. XX to XX

NRC Regulatory Guide 1.182, Assessing and Managing Risk Before Maintenance Activities at Nuclear Power Plants

NUMARC 93-01, Industry Guideline For Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, Section 11- Assessment of Risk Resulting from Performance of Maintenance Activities, dated February 11, 2000

PSA white paper on risk associated with operator actions for a loss of control room chilled waterHope Creek Shutdown Safety Status, 04/17/2006 and 04/18/2006PSEG River Grass Data Spreadsheet

E-18 Calculation, Rev. 1 and 2, Selection of Overload Heaters For AC MOVs and Continuous Duty Motors

M-076, Rev. 8, Design Specification for Service Water Self-Cleaning Strainers

DE-CB.EA/EP/EQ-0052, Rev. 2, Configuration Baseline Documentation for Station ServiceWater System Hope Creek Maintenance Rule Computer System Service Water Information

Section 1R14: Operator Performance During Non-routine Evolutions and EventsProceduresHC.OP-SO.AE-0001, Rev. 44, Feedwater System OperationHC.OP-IO.ZZ-0004, Rev. 66, Shutdown From Rated Power to Cold Shutdown

HC.OP-ST.BB-0001, Rev. 34, Recirculation Jet Pump Operability - DailyHC.ER-AP.BB-0002, Rev. 7, Hope creek Reactor Recirculation Pump Piping Vibration MonitoringCorrective Action Notifications202513522028204120278329202879502028755320287559

Orders7005606370050125

Other DocumentsIPTE 06-002, Rev 0,1,2 dated June 2006.

Titled - "RFO-13 Post "B" Reactor RecirculationPump Replacement and Piping Support Modification Vibration Evaluation at Core Flows greater than 100 Mlb/hr." Recirculation Pump Vibration Monitoring Just-In-Time training package Feedwater Control System Licensed Operator Lesson Plan

H-1-BB-MDC-4000, Reactor Recirculation System Acoustic Model, dated December 29, 2005

GENE-0000-0035-6906, Rev. 4, Recirculation & RHR Piping Start Up Test CriteriaResults of Reactor Recirculation Acoustic Vibration Testing - June 2006

Plant Historian plots of recirculation pump flow and reactor power vs time April 6, 2006

Prompt Investigation for Recirc runback during reactor shutdown on April 6, 2006

2Attachment

Section 1R15: Operability EvaluationsProceduresHC.MD-CM.EA-0003, Rev. 25, Service Water Strainer Overhaul & RepairHC.MD-CM.EA-0003, Rev. 27, Service Water Strainer Overhaul & Repair

HC.MD-PM.EA-0001, Rev. 18, Service Water Strainer - Clean and Inspect

HC.MD-PM.EA-0001, Rev. 19, Service Water Strainer - Clean and Inspect

HC.MD-PM.EA-0001, Rev. 20, Service Water Strainer - Clean and Inspect

HC.MD-PM.EA-0001, Rev. 21, Service Water Strainer - Clean and Inspect

NC.WM-AP.ZZ-0000, Rev. 10, Notification Process

NC.WM-AP.ZZ-0000, Rev. 13, Notification Process

NC.WM-AP.ZZ-0002, Rev. 8, Corrective Action Process

NC.WM-AP.ZZ-0002, Rev. 9, Corrective Action Process

NC.CC-AP.ZZ-0080, Rev. 19, Engineering Change Process

NC.CC-AP.ZZ-0081, Rev. 8, Engineering Change Implementation and Test Process

HC.OP-AP.ZZ-0108, Rev. 23, Operability Assessment and Equipment Control ProgramHC.OP-AP.ZZ-0108, Rev. 24, Operability Assessment and Equipment Control ProgramHC.OP-AP.ZZ-0108, Rev. 25, Operability Assessment and Equipment Control ProgramLS-AA-120, Rev. 5, Issue Identification and Screening Process

HC.OP-AR.ZZ-0001, Rev. 16, Overhead Annunciator Window Box A1

HC.OP-AP.ZZ-0109, Rev. 14, Equipment Operational Control

HC.OP-AB.COOL-0001, Rev. 4, Station Service Water

HC.OP-AB.COOL-0001, Rev. 8, Station Service Water

HC.OP-ST.GK-0002, Rev. 6, Control Room Emergency Filtration System Isolation /Actuation Functional Test - 18 Months

HC.IC-FT.GK-0001, Rev. 6, Control Room Emergency Filtration System Flow Measurements

HC.MD-CM.KJ-0004, Rev. 11, Diesel Generator Lubrication System Maintenance and RepairHC.IC-FT.PE-0008, Rev. 5, Time Interval Test Emergency Load Sequencer System Diesel Generator D, 1DC428

HC.OP-ST.KJ-0008, Rev. 33, Integrated Emergency Diesel Generator 1DG400 Test - 18Months

MA-AA-716-004, Rev. 4, Conduct of Troubleshooting

MA-HC-716-004-001, Rev. 0, Conduct of Troubleshooting

HC.RE-ST.SE-0003, Rev. 19, LPRM Calibration SurveillanceHC.OP-IS.BE-0001(Q), Rev. 36, A & C Core Spray Pumps-AP206 and CP206 - In-Service Test

HC.OP-IS.BE-0101(Q), Rev. 23, Core Spray Subsystem A Valves - Inservice TestMA-AB-772-301, Rev. 1, Procedure for Dresden and Quad Cities Recirculating MG Set Voltage Regulator Tuning

HC.IC-SC.BJ-0011, Rev.8, HPCI - Division 1 Channel L-4805-1 Suppression Chamber Water LevelDrawingsPN1-B31-1030-0024, Reactor recirculation pump and MG set schematicPN1-B31-S0001-0120, General Electric Recirc MG set voltage regulator schematic

M-55-1, High Pressure Coolant Injection

A-13AttachmentCorrective Action Notifications2028852320288483

288035

286560

280701

285752

201786912017895320204814

204953

206335

206474

212968

2131742028056920280959

281813

283448

284983

284984

2863622028962820278147

277825

274462

276142

277423

2778912027806820278533

278666

278760

278899

281682

2824992028291120284680

285325

279434

278996

278850

283884Orders8008968560063505

30059866

30097091

30124011

30130802

60038730

600430836004840360050019

60050123

60062268

60062304

60062305

70037109

700371817004161470041902

70043287

70056583

70056729

70057117

70058063

800324508006808780076640

80076763

80079630

80089544

50080604

60061841

700558643008448260061905

60061918

60061965

60062341

60062683

60062957

700547867005592570056104

70056913

90002327

60062087

70057358Other DocumentsHope Creek Inservice Testing Program Basis Data Sheets for 1BEV-028E.Q. Maintenance and Surveillance Information Sheet for Reactor Core SprayNRC Inspection Manual Part 9900: Technical Guidance Operability Determinations &

Functionality Assessments for Resolution of Degraded or Nonconforming conditions Adverse to Quality or Safety

SC-BJ-0008-3, HPCI Suppression Chamber Level Low

SC-BJ-0004, Setpoint Calculation - HPCI (Suppression Pool Level High)

Hope Creek RF13 Refuel Outage

CRB 26-59, engineering white paper on blistered control rod

26-59

OTDM

HC-2006-0008, Disposition of blistered control rod blade 26-59

Hope Creek Shutdown Safety Status, 04/17/2006 and 04/18/2006PSEG River Grass Data Spreadsheet

E-18 Calculation, Rev. 1 and 2, Selection of Overload Heaters For AC MOVs and Continuous Duty Motors

M-076, Rev. 8, Design Specification for Service Water Self-Cleaning Strainers

DE-CB.EA/EP/EQ-0052, Rev. 2, Configuration Baseline Documentation for Station ServiceWater System Hope Creek Maintenance Rule Computer System Service Water Information Hope Creek Reactor Engineering Startup Reactivity Plan to Maximum Power Based on Feed Pump Configuration, 05/10/2006

Section 1R17: Permanent Plant ModificationsProceduresHC.ER-AP.BB-0001(Q), Rev. 6,

HC Reactor Recirculation Pumps VibrationMonitoring

HC.OP-SO.BB-0002(Q), Rev. 59, Reactor Recirculation System Operation

A-14AttachmentHC.OP-DL.ZZ-0004(Q), Rev. 31, Log 4 Reactor Building LogOther DocumentsECN

80076232, Rev. 5, HC "B" Recirc Pump Internals ReplacementED-221-1, Rev. 0IR0, Drywell Building RACS Water To Pump BP-201

SC-ED-0503, Rev.1IR0, Loop Tolerance Calculations For 1ED FISL N004A&B

GE-NE-0000-0036-1608, Rev. 0, Seal Purge Setting Procedure Reactor Recirculation Pump 4th Generation ModificationM:\Shared\HC Reactor Recirc Vibrations\Cycle 14 Startup Data, Rev. 0, Reactor Recirculation Critical Speed Review Cycle 14 Startup Review

Section 1R19: Post-Maintenance TestingProceduresHC.MD-ST.ZZ-0009(Q), Rev. 17, Motor Operated Valve Thermal Overload ProtectionSurveillance

HC.OP-IS.BC-0103(Q), Rev. 22, Residual Heat Removal Subsystem C Valves - Inservice TestNC.NA-TS.ZZ-0050, Maintenance Testing Program Matrix

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

HC.MD-CM.EA-0003(Q), Service Water Strainer Overhaul & Repair, Rev. 27

HC.OP-IS.EA-0002(Q), B Service Water Pump-BP502 - Inservice Test, Rev. 44

HC.OP-ST.GK-0003(Q), B - Control Room Emergency Filtration System Functional Test -

Monthly, Rev. 5

HC.OP-IS.BE-0001(Q), Rev. 36, A & C Core Spray Pumps-AP206 and CP206 - In-Service Test

HC.OP-IS.BE-0101(Q), Rev. 23, Core Spray Subsytem A Valves - Inservice Test

HC.MD-CM.EA-0002(Q), Rev. 17, Service Water Pump Overhaul Repair

HC.MD-CM.EA-0001(Q), Rev. 22, Service Water Pump & Motor Removal & Replacement

HC.MD-PM.EA-0002(Q), Rev. 13, Service Water Intake Bay Silt Survey and Silt Removal

HC.OP-IS.EA-0001(Q), Rev. 39, A Service Water Pump - AP502 - Inservice Test

HC.MD-CM.KJ-0004, Rev. 11, Diesel Generator Lubrication System Maintenance and RepairDrawingsE-6231-0 sheet 10, Electrical schematic diagram residual heat removal system RHR pump minflow bypass valvesCorrective Action Notifications2028740420287060

257550

255075

254827

254760

2546342023479020231157

229555

227580

287588

287606

2878032021867120243514

288523

288523

288483

288381

2883332028001920280080

280229

279864

282499

274462

2761422027742320277891

278068

278533

278666

2787602027889920281682

282499

282911

284680

285325

A-15AttachmentOrders5007880360058580

60061526

50096174

600633008008968560063505

60063201

800762323011857380089186

70056913

600623413008448260061905

60061918

600619656006234160062683

60062957

700547867005592570056104

70056913

90002327Other DocumentsHope Creek Inservice Testing Program Basis Data Sheets for 1BEV-028E.Q. Maintenance and Surveillance Information Sheet for Reactor Core SprayReactor Recirculation Pump Plant Data dated April 29, 2006

VTD

PN1-A41-8010-0052 GE Refueling Platform Operation Technical Decision Making & Adverse Monitoring Plan HC-2006-009

Section 1R20: Refueling and Outage ActivitiesProceduresNC.NA-AP.ZZ-0055, Outage Management ProgramNC.OM-AP.ZZ-0001, Outage Risk Assessment

HC.OP-IO.ZZ-0002, Rev. 44, Preparation for Plant Startup

HC.OP-IO.ZZ-0003, Rev. 74, Startup From Cold Shutdown to Rated Power

HC.OP-IO.ZZ-0004, Rev. 66, Shutdown From Rated Power to Cold Shutdown

HC.OP-AB.RPV-0009, Shutdown Cooling

HC.MD-FR.KE-0036, Rev. 11, Reactor Pressure Vessel Assembly

HC.OP-GP.ZZ-0002, Rev. 12, Primary Containment Closeout

HC.RE-FR.ZZ-0001, Rev. 28, Fuel Handling Controls

HC.RE-FR.ZZ-0014, Rev. 7, New Fuel Inspection, Channeling, and Storage

HC.OP-AB.RPV-0009, Rev. 5, Shutdown Cooling

HC.OP-SO.BC-0002, Rev. 18, Decay Heat Removal Operation

HC.OP-IO.ZZ-0001, Rev. 18, Refueling to Cold Shutdown

HC.ER-AP.BB-0001, Rev. 5, Hope Creek Reactor Recirculation Pumps Vibration Monitoring

HC.OP-SP.BF-0001, Rev. 6, Control Rod Drive Mechanism / Blade Simultaneous Removal

HC.RA-IS.ZZ-0010, Rev. 13, Containment Isolation Valve Type C Leak Rate Test

HC.RA-IS.ZZ-0017, Rev. 5, Reactor Coolant System Pressure Isolation Valves Seat Leakage Measurement/TestDrawingsM-53-1, Sheet 1, Rev. 29, Fuel Pool Cooling & Torus Water Cleanup Corrective Action Notifications2027840020278441

282029

282517

2807602028095220281797

283537

2844462028389220282550

278486

2784472027883720281583

276570

2830572027981320280986

280990

2811272028112920281330

281397

281439

A-16AttachmentOrders70057641800870448008886360062346600623477005667730115511301157565008075970056836Other DocumentsHope Creek RF13 Outage Risk Assessment ReportNRC Information Notice 2002-26, Failure of Steam Dryer Cover Plate After a Recent PowerUprate

GENE-0000-0053-6264-00-R1, MSIV Body to Bonnet Replacement Stud Use "As-Is" Evaluation Hope Creek Work Clearance Documents

4154067 and 4165359

Hope Creek Refuel Outage System Preparation Documents Hope Creek Refuel Outage 13 Turnover Log - ISI/CISI/SPT/Snubbers/SupportsSection 1R22: Surveillance TestingProceduresHC.CH-RC.ZZ-0002 Rev. 17, Gross Beta and Tritium by Liquid ScintillationHC.OP-DL.ZZ-0026 Rev. 104, Surveillance LogHC.IC-FT.SK-0016, Rev. 17, Radiation Monitoring - Channel D Monitor H1SK-1SKLY-4930

Drywell Leak Detection Sump Monitoring System (DLD-SMS)

HC.RA-IS.ZZ-0010, Rev. 13, Containment Isolation Valve Type C Leak Rate Test

HC.RA-IS.ZZ-0017, Rev. 5, Reactor Coolant System Pressure Isolation Valves Seat Leakage Measurement/Test

HC.OP-ST.KJ-0006, Rev. 31, Integrated Emergency Diesel Generator 1BG400 Test - 18MonthsCorrective Action Notifications2025334720276310

2374452025279020287588

2895652027981320280986

2809902028112720281129

2813302028139720281439

2794342027921820280967Orders5009466850081260

50082713

500807596006234660062347

70056677

301155113011575650080759

50082684

600621523006226450080759

50080634

500818075008082150081847

30015756

500818855008184330115511

50080664

50080675

Section 1R23: Temporary Plant ModificationsProceduresSH.MD-AP.ZZ-0002, Rev. 9, Maintenance Department Troubleshooting and RepairMA-AA-716-004, Rev. 4, Conduct of Troubleshooting

MA-HC-716-004-001, Rev. 0, Conduct of Troubleshooting

SH.OP-AP.ZZ-0108, Rev. 22, Operability Assessment and Equipment Control ProgramNC.NA-AP.ZZ-0008, Rev. 20, Configuration Control Program

NC.DE-AP.ZZ-0030, Rev. 5, Control of Temporary Modifications

HC.MD-ST.KF-0001, Rev. 12, Polar Crane Periodic Inspection

A-17AttachmentNC.WM-AP.ZZ-0003, Rev. 5, Regular Maintenance ProcessHC.DE-AP.ZZ-0060, Rev. 0, Functional Classification Methodology For Component Data Module Functional Location Within SAP/R3 For Hope Creek Generating StationDrawingsPM063Q-0065, Sheet 2, Rev. 0, Polar Crane Schematic Diagram - Main Hoist Power Corrective Action Notifications202786562027528520278656202851992028644020278542

Orders7005622930118573

Other DocumentsASME B30.2-2005, Overhead and Gantry Cranes (Top Running Bridge, Single or MultipleGirder, Top Running Trolley Hoist)

Refuel Floor Activity Logs

Section 1EP6: Drill EvaluationProceduresHC.OP-AB.CONT-0002(Q), Primary Containment, Rev. 2HC.OP-EO.ZZ-0101(Q), Reactor Pressure Vessel Control, Rev. 10

NC.EP-EP.ZZ-0404(Q), Protective Action Recommendations (PARS) Upgrades, Rev. 2

HC.OP-AB.COMP-0002(Q), Primary Containment Instrument Gas, Rev 4Corrective Action Notifications2028743820287762

Other DocumentsSimulator Scenario Guide

SG-263, Reactor Recirc Pump Trip / RWCU Leak / PCIG Leak /Failure of RPS, Rev 3

Section 2OS1: Access Control to Radiologically Significant AreasCorrective Action Notifications20279873Other DocumentsRadiation Work Permit #11Shielding package #2006-036Section 2OS2:

ALARA Planning and ControlsALARA Reviews: 2006-082; 2006-141

A-18Attachment

Section 4OA1: Performance Indicator VerificationProceduresHC.CH-DG.PI-0001, Rev. 0, Hope Creek Chemistry Desk Top Guide

NRC PerformanceIndicator Status Determination

HC.CH-TI.ZZ-0012, Rev. 50, Chemistry Sampling Frequencies, Specifications, and Surveillances

HC.OP-DL.ZZ-0026, Rev. 104, Surveillance LogLS-AA-2090, Rev. 4, Monthly Data Elements for NRC Reactor Coolant System (RCS) SpecificActivity

LS-AA-2001, Rev. 4, Collecting and Reporting of NRC Performance Indicator DataLS-AA-2100, Rev. 5, Monthly Data Elements for NRC Reactor Coolant System (RCS) LeakageLS-AA-2010, Rev. 4, Monthly Data Elements for NRC/WANO Unit/Reactor ShutdownOccurrences

LS-AA-2030, Rev. 4, Monthly Data Elements for NRC Unplanned Power Changes per 7000Critical HoursCorrective Action Notifications202009362020055120237921202458772025595120200553

Other DocumentsMonthly Operating Reports for the Months of October 2004 through January 2006LER 050000354/2004010, Manual Reactor Scram Due to Moisture Separator Dump Line Failure

LER 050000354/2005002, Through-Wall Leak on 'B' Reactor Recirculation System Decontamination Port

LER 050000354/2005003, Reactor Coolant System Leak from Check Valve Position Indicator

LER 050000354/2005008, Technical Specification Shutdown due to 'B' Suppression Chamberto Drywell Vacuum Breaker Not Closed

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 Brief

HU-AA-1101, Rev. 1, Change Management

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

NC.NA-AP.ZZ-0089, Rev. 0, Reactivity Management

OP-AA-300-1540, Rev. 3, Reactivity Management Administration

A-19AttachmentCorrective Action Notifications2026504420216735

235815

250244

233706

261768

259571

2607102025630220263496

20186751

20174947

20175121

20175996

201808882018129220193148

20199679

20199983

20199984

200795

2007962020367520214921

214923

215389

215390

216170

2166002021776720220180

201993

220400

258640

269559

2262402024004520265806

201991

282581

281397

285708

285326Orders70038773700435217004352270051281Other DocumentsPSEG Metrics for Improving the Work Environment, Salem and Hope Creek Generating Stations, Quartely Report, April 28, 2006

UFSAR Section 9.2, Water Systems Hope Creek Service Water Deicing System presentation to Plant Health Committee dated June 22, 2006

Section 4OA5: Other ActivitiesProceduresHC.OP-AB.BOP-0004(Q), Rev. 11, Grid DisturbancesNC.WM-AP.ZZ-0001(Q), Rev. 12, Work Management Process

NC-CC-DG.ZZ-0003(Z), Rev. 3, PRA Weekly Risk Assessment (a)(4) Desktop Guide

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

SH.OP-DD.ZZ-0001(Z), Rev. 3, Electric System Emergency Operations and Electric System Operator Interface

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

HC.OP-ST.BC-0009, Rev. 5, Residual Heat Removal System RHR heat Exchanger FlowMeasurement - 18 MonthCorrective Action Notifications2028398820281777

Orders50093314500827135008126070054151

A-20Attachment

LIST OF ACRONYMS

ALARAAs Low As Is Reasonably AchievableASMEAmerican Society of Mechanical Engineers

CA [[]]

PC orrective Action Program

CC [[]]

AC ommon Cause Analysis

CF [[]]

RCode of Federal Regulations

CMC orrective Maintenance

DC [[]]

PD esign Change Package

ED [[]]

GE mergency Diesel Generator

HCG [[]]

SH ope Creek Generating Station

HPC [[]]

IHigh Pressure Coolant Injection

HXH eat Exchanger

INP [[]]

OI nstitute of Nuclear Power Operations

IS [[]]

II nservice Inspection

LOP /

LOCALoss of Power/Loss of Coolant Accident

MRM aintenance Rule

MSI [[]]

VM ain Steam Isolation Valve

NC [[]]

VN on-cited Violation

ND [[]]

EN ondestructive Examination

NR [[]]

CN uclear Regulatory Commission

NR [[]]

RNuclear Reactor Regulation

PIPerformance Indicator

PMP reventive Maintenance

PSEGP ublic Service Enterprise Group Nuclear

LLC [[]]

RH [[]]

RResidual Heat Removal

rpmRevolutions Per Minute

RP [[]]

VR eactor Pressure Vessel

RW [[]]

PR adiation Work Permit

SAC [[]]

SS afety Auxiliary Cooling System

SCW [[]]

ES afety Conscious Work Environment

SD [[]]

PS ignificance Determination Process

SJA [[]]

ES team Jet Air Ejector

STACSS afety and Turbine Auxiliary Cooling System

TIT emporary Instruction

TO [[]]

LThermal Overload

TST echnical Specificaion

UFSA [[]]

RU pdated Final Safety Analysis Report