Text

IR 05000272-07-002, 05000311/2007002; 01/01/2007 - 03/31/2007; Salem Nuclear Generating Station Units 1 and 2; Maintenance Effectiveness
	ML071350075
Person / Time
Site:	Salem
Issue date:	05/11/2007
From:	Burritt A L; Reactor Projects Branch 3
To:	Levis W; Public Service Enterprise Group
	Burritt A
References
	IR-07-002
	Download: ML071350075 (38)
	v • d • e

May 11, 2007

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

SUBJECT: SALEM NUCLEAR GENERATING STATION - NRC INTEGRATEDINSPECTION REPORT 05000272/2007002 and 05000311/2007002

Dear Mr. Levis:

On March 31, 2007, the US Nuclear Regulatory Commission (NRC) completed an inspection atthe Salem Nuclear Generating Station. The enclosed integrated inspection report documents the inspection results, which were discussed on April 5, 2007, with Mr. Joyce and other members of your staff.The inspection examined activities conducted under your license as they relate to safety andcompliance with the Commission's rules and regulations and with the conditions of your license.

The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel. The report documents one self-revealing finding of very low safety significance (Green). Thisfinding was determined to involve violations of NRC requirements. However, because of the very low safety significance and because it is entered into your corrective action program, the NRC is treating this finding as a non-cited violation (NCV) consistent with Section VI.A of the NRC Enforcement Policy. If you contest any NCV in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001; with copies to the Regional Administrator, Region I; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at the Salem Nuclear Generating Station.In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, itsenclosure, and your response (if any) will be available electronically for public inspection in the Mr. W. Levis2NRC 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/Arthur L. Burritt, Chief Projects Branch 3 Division of Reactor ProjectsDocket Nos:50-272; 50-311License Nos:DPR-70; DPR-75

Enclosure:

Inspection Report 05000272/2007002 and 05000311/2007002

w/Attachment:

Supplemental Informationcc w/encl:T. Joyce, Site Vice President - Salem D. Winchester, Vice President Nuclear Assessments B. Clark, Director - Finance C. J. Fricker, Salem Plant Manager J. J. Keenan, General Solicitor, PSEG M. Wetterhahn, Esquire, Winston and Strawn, LLP L. A. Peterson, Chief of Police and Emergency Management Coordinator P. Baldauf, Assistant Director, NJ Radiation Protection Programs K. Tosch, Chief, Bureau of Nuclear Engineering, NJ Dept. of Environmental Protection

H. Otto, Ph.D., Administrator, Interagency Programs, DNREC Division of Water Resources, State of Delaware Consumer Advocate, Office of Consumer Advocate, Commonwealth of Pennsylvania N. Cohen, Coordinator - Unplug Salem Campaign E. Zobian, Coordinator - Jersey Shore Anti Nuclear Alliance NRC Public Document Room or from the Publicly Available Records (PARS) component of NRC's document system (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,/RA/Arthur L. Burritt, Chief Projects Branch 3 Division of Reactor ProjectsDocket Nos:50-272; 50-311 License Nos:DPR-70; DPR-75

Enclosure:

Inspection Report 05000272/2007002 and 05000311/2007002

w/Attachment:

Supplemental Informationcc w/encl:

T. Joyce, Site Vice President - Salem D. Winchester, Vice President Nuclear Assessments B. Clark, Director - Finance C. J. Fricker, Salem Plant Manager J. J. Keenan, General Solicitor, PSEG M. Wetterhahn, Esquire, Winston and Strawn, LLP L. A. Peterson, Chief of Police and Emergency Management Coordinator P. Baldauf, Assistant Director, NJ Radiation Protection Programs K. Tosch, Chief, Bureau of Nuclear Engineering, NJ Dept. of Environmental Protection H. Otto, Ph.D., Administrator, Interagency Programs, DNREC Division of Water Resources, State of Delaware Consumer Advocate, Office of Consumer Advocate, Commonwealth of Pennsylvania N. Cohen, Coordinator - Unplug Salem Campaign E. Zobian, Coordinator - Jersey Shore Anti Nuclear Alliance Distribution w/encl:S. Collins, RAM. Dapas, DRA D. Lew, DRP J. Clifford, DRP

A. Burritt, DRP

C. Khan, DRP D. Schroeder, DRP, Senior Resident Inspector H. Balian, DRP, Resident Inspector K. Venuto, DRP, Resident OA J. Lamb, RI OEDO J. Lubinski, NRR H. Chernoff, NRR R. Ennis, NRR, PM J. Shea, NRR D. Collins, NRR S. Bailey, NRR T. Valentine, NRR ROPreports@nrc.gov Region I Docket Room (with concurrences)DOCUMENT NAME: C:\FileNet\ML071350075.wpd ML071350075 SUNSI Review Complete: ALB (Reviewer's Initials)

After declaring this document "An Official Agency Record" it will/will not be released to the Public.To receive a copy of this document, indicate in the box:

" C" = Copy without attachment/enclosure " E" = Copy with attachment/enclosure " N" = No copyOFFICERI/DRP RI/DRPNAMEDSchroeder/ALB for ABurritt/DATE5 /11 /075 / 11 /07 OFFICIAL RECORD COPYU.S. NUCLEAR REGULATORY COMMISSION REGION I Mr. W. LevisEnclosure iiDocket Nos.50-272, 50-311License Nos.DPR-70, DPR-75 Report Nos.05000272/2007002 and 05000311/2007002 Licensee:Public Service Enterprise Group Nuclear LLC Facility:Salem Nuclear Generating Station, Units 1 & 2 Location:P.O. Box 236Hancocks Bridge, NJ 08038Dates:January 1, 2007 through March 31, 2007 Inspectors:D. Schroeder, Senior Resident InspectorH. Balian, Resident Inspector J. Schoppy, Jr., Senior Reactor Inspector S. McCarver, Project Engineer J. Furia, Senior Health Physicist M. Snell, Reactor Inspector D. Tifft, Reactor Inspector M. Patel, Reactor Inspector A. Patel, Reactor Inspector N. Perry, Senior Emergency Preparedness Inspector R. Cureton, Emergency Preparedness Inspector R. Nimitz, Senior Health PhysicistApproved By:Arthur L. Burritt, Chief Projects Branch 3 Division of Reactor Projects Enclosure iiiTABLE OF CONTENTSREACTOR SAFETY.........................................................11R01Adverse Weather Protection.......................................1 1R04Equipment Alignment.............................................1 1R05Fire Protection..................................................2 1R06Flood Protection Measures........................................31R11Licensed Operator Requalification Program............................6 1R12Maintenance Effectiveness........................................61R13Maintenance Risk Assessments and Emergent Work Control..............91R15Operability Evaluations...........................................91R17Permanent Plant Modifications.....................................101R19Post-Maintenance Testing........................................111R22Surveillance Testing.............................................12 1EP2Alert and Notification System (ANS)................................121EP3Emergency Response Organization (ERO) Augmentation................131EP4Emergency Action Level (EAL) and Emergency Plan Changes............131EP5Correction of Emergency Preparedness Weaknesses and Deficiencies.....131EP6Drill Evaluation.................................................14RADIATION SAFETY.......................................................142OS1Access Control to Radiologically Significant Areas.....................14 2OS2ALARA Planning and Controls.....................................152OS3Radiation Monitoring Instrumentation and Protective Equipment...........16OTHER ACTIVITIES........................................................164OA1Performance Indicator (PI) Verification..............................16 4OA2Identification and Resolution of Problems............................174OA5Other Activities.................................................17 4OA6Meetings, Including Exit..........................................19SUPPLEMENTAL INFORMATION............................................A-1KEY POINTS OF CONTACT................................................A-1LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED...........................A-1LIST OF DOCUMENTS REVIEWED..........................................A-2 LIST OF ACRONYMS.....................................................A-12 Enclosure iv

SUMMARY OF FINDINGS

IR 05000272/2007002, 05000311/2007002; 01/01/2007 - 03/31/2007; Salem NuclearGenerating Station Units 1 and 2; Maintenance Effectiveness.The report covered a 13-week period of inspection by resident inspectors, and an announcedinspection by a regional radiation specialist, emergency preparedness inspector, and a regional project engineer . One Green non-cited violation (NCV) and one unresolved item were identified. The significance of most findings is indicated by their color (Green, White, Yellow, or Red) using Inspection Manual Chapter (IMC) 0609, "Significance Determination Process" (SDP). Findings for which the SDP does not apply may be Green or be assigned a severity level after NRC management review. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, "Reactor Oversight Process," Revision 4, dated December 2006.A.

NRC-Identified and Self-Revealing Findings

Cornerstone: Mitigating Systems

Green.

A self-revealing non-cited violation of 10 CFR 50, Appendix B, Criterion V,"Instructions, Procedures, and Drawings," was identified because PSEG did not conduct maintenance in accordance with appropriate written procedures. Specifically, the pump packing was not adequately cooled during the PMT, damaging the 15 SWP. The finding is more than minor because it impacted the Mitigating Systems cornerstoneobjective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, incorrectly performed maintenance reduced the availability of the 15 SWP. In accordance with IMC 0609, Appendix A, "Significance Determination of Reactor Inspection Findings for At-Power Situations," the inspectors conducted a Phase 1 screen and determined that this finding required a Phase 2 analysis because both the Initiating Event and Mitigating Systems Cornerstones were adversely impacted by the 15 SWP unavailability. Based upon the Risk-Informed Notebook for Salem Generating Station not containing a Loss of Service Water worksheet, the Senior Reactor Analyst (SRA) conducted a Phase 3 risk assessment and determined that the finding was of very low safety significance (Green).The performance deficiency has a cross-cutting aspect in the area of humanperformance because PSEG did not effectively communicate human error prevention techniques. Maintenance technicians assigned to perform the post-maintenance test were unfamiliar with the task. The pre-job brief did not discuss in detail the application of external cooling water to the packing gland during packing break in. At the job site, maintenance technicians proceeded with the post-maintenance test in the face of uncertainty, resulting in equipment damage. (Section 1R12)

B.Licensee Identified Violations

None

REPORT DETAILS

Summary of Plant StatusUnit 1 began the period at 100 percent (%) power. End of cycle coastdown commenced onMarch 9, 2007, with power reducing approximately 1% per day until the unit was shut down at 8:00 pm on March 27, 2007, to start the eighteenth refuel outage of Unit 1 (1R18). Mode 5 was reached at 5:00 am on March 28, 2007, and Mode 6 was achieved at 10:30 am on March 31, 2007. The refuel outage was in progress at the end of the inspection period.Unit 2 began the period at 100% power. On February 10, 2007, power was reduced to 85% forturbine valve testing. Power was returned to 100% on February 11, 2007. On March 21, 2007, at 9:30 am, power was reduced to 95% in accordance with plant procedures in response to an unplanned partial loss of circulating water. Power was raised to 100% at 10:00 pm on March 21, 2007, where it remained until the end of the inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems and Barrier Integrity1R01Adverse Weather Protection (71111.01)

a. Inspection Scope

(2 samples)The inspectors reviewed PSEG's preparation and response to two site specific weatherrelated conditions. First, the inspectors reviewed adverse weather preparation activities related to the potential for river grass intrusion conditions. Inspectors assessed implementation of PSEG's grassing readiness plan through plant walkdowns, corrective action program review, and discussions with cognizant managers and engineers.

Documents reviewed by inspectors are listed in the attachment.Second, the inspectors reviewed PSEG's response to abnormally cold weather the weekof February 5, 2007. The inspectors reviewed Units 1 and 2 service water system performance and impact on supported systems. The review included Salem's response to a degraded ice barrier at the service water intake structure and to unusually low river water levels caused by high winds coincident with spring tides. The inspectors observed control room and equipment operator response to the adverse environmental condition, including additional monitoring of affected plant equipment.

b. Findings

No findings of significance were identified.

1R04 Equipment Alignment (71111.04).1Partial Walkdown (4 samples)

a. Inspection Scope

The inspectors performed partial walkdowns of four systems comprising four samples toverify the operability of redundant or diverse trains and components when safety equipment was inoperable. The inspectors focused their review on potential discrepancies that could impact the function of the system, and therefore, potentially increase risk. The inspectors reviewed applicable operating procedures, walked down control systems components, and verified that selected breakers, valves, and support equipment were in the correct position to support system operation. The inspectors also verified that PSEG personnel had properly identified and resolved equipment alignment problems that could cause initiating events or impact the capability of mitigating systems or barriers and entered them into the corrective action program. Documents reviewed are listed in the attachment. The following systems were walked down:Unit 2 boration flow paths and redundant charging pumps following the emergentfailure of the No. 23 charging pumpUnit 1 and Unit 2 containment spray systems during planned maintenance on thecontainment spray systemUnit 1 and Unit 2 carbon dioxide (CO 2) fire suppression systems following designchanges and restoration to service following a system outageUnit 1 service water (SW) header No. 12 during the No. 11 SW header outage.2Complete Walkdown (IP 71111.04S - 1 sample)

a. Inspection Scope

The inspectors conducted one complete walkdown of accessible portions of the SalemUnit 2 auxiliary feedwater system to verify that the system was properly configured, hangers and supports were correctly installed and functional, pump oil reservoir levels were normal, and to identify any discrepancies between the existing valve lineup and the prescribed lineup. The inspectors used PSEG procedures and other documents to verify proper system alignment and functional capability. The inspectors reviewed corrective action evaluations associated with the system to determine whether equipment alignment problems were being identified and appropriately resolved.

Documents reviewed are listed in the attachment.

b. Findings

No findings of significance were identified.

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

a. Inspection Scope

(11 samples)The inspectors conducted a tour of the eleven areas listed below to assess the materialcondition and operational status of fire protection features. The inspectors verified that 3Enclosure combustibles and ignition sources were controlled in accordance with PSEG'sadministrative procedures; fire detection and suppression equipment was available for use; that passive fire barriers were maintained in good material condition; and that compensatory measures for out-of-service, degraded, or inoperable fire protection equipment were implemented in accordance with PSEG's fire plan. Documents reviewed are listed in the attachment.Unit 1 and Unit 2 Pre-Fire Plan FRS-II-511, Electrical Penetration Area Elevation:78' - 0"Unit 1 and Unit 2 Pre-fire Plan FRS-11-512, Mechanical Piping Penetration AreaElevations: 78' & 100'Salem Pre-Fire Plan FRS-III-815, Fire/Fresh Water Pump HouseSalem Pre-Fire Plan FRS-III-821, Station Black-Out Compressor BuildingUnit 1 and Unit 2 Pre-Fire Plan FRS-II-444 Demineralized Ion Exchanger Area*Unit 3 Pre-Fire Plan FRS-III-818, Combustion Turbine

Unit 1 and Unit 2 Pre-Fire Plan FRS-II-912, Service Water Pipe Trench & Tunnel

b. Findings

No findings of significance were identified..2Fire Protection - Drill Observation (71111.05A)

a. Inspection Scope

(1 sample)The inspectors observed one fire drill conducted in the Salem Unit 1 turbine building atelevation eighty eight feet. The drill was observed to evaluate the readiness of the plant fire brigade to fight fires. The inspectors verified that PSEG staff identified deficiencies, openly discussed them in a self-critical manner at the drill debrief, and took appropriate corrective actions. Specific attributes evaluated were:

(1) proper wearing of turnout gear and self-contained breathing apparatus;

(2) proper use and layout of fire hoses; (3)employment of appropriate fire fighting techniques;

(4) sufficient fire fighting equipment brought to the scene;

(5) effectiveness of fire brigade leader communications, command, and control;

(6) search for victims and propagation of the fire into other plant areas;

(7) smoke removal operations;

(8) utilization of pre-planned strategies; (9)adherence to the pre-planned drill scenario; and

(10) drill objectives.

b. Findings

No findings of significance were identified.

1R06 Flood Protection Measures (71111.06).1Operating Experience Smart Sample (OpESS) FY2007-02 Review

a. Inspection Scope

(1 sample)Internal Flooding Review. NRC Operating Experience Smart Sample (OpESS) FY2007-02 is related to NRC Information Notice 2005-30 and issues associated with conduit/hydrostatic seal issues. The inspectors evaluated internal flood protection measures for the 4KV vital switchgear rooms, fuel oil transfer pump rooms, and residual heat removal (RHR) pump rooms for both Salem Units. The inspectors walked down the areas to assess operational readiness of various features in place to protect redundant safety-related components and vital electric power systems from internal flooding. These features included plant drains, flood barrier curbs, and wall penetration seals. The inspectors conducted a detailed walkdown of the turbine and auxiliary buildings with a design engineer to assess potential internal flood vulnerabilities. The inspectors also reviewed the results of flood barrier penetration seal inspections, flooding evaluations, preventive maintenance history, and corrective action notifications associated with flood protection measures. Finally, the inspectors interviewed main control room operators regarding their knowledge of indications, procedures and required actions during a postulated turbine building piping rupture. Documents reviewed are listed in the attachment.

b. Findings

The inspectors identified several potential vulnerabilities to internal flooding, applicableto both Salem units, that called into question PSEG's design control as described in the Salem Updated Final Safety Analysis Report (UFSAR). In particular, the inspectors identified the following concerns:(1) UFSAR Section 3.6.4.3.2 states that "Design basis cracks were also postulated tooccur in high energy lines at the most adverse locations with respect to safeguards equipment and structures. For Unit 1 design basis cracks only were postulated for those systems whose pressure is more than 275 psig or whose temperature is more than 200F." The inspectors found no apparent high energy line break (HELB) barriers and/orengineering evaluation for the high energy piping (i.e. heating steam & heating water systems) in the auxiliary building 84' corridor adjacent to the Unit 1 & 2 460V vital switchgear rooms. The 460V switchgear rooms contain redundant safe shutdown equipment (A, B, & C 230V vital buses; A, B, & C 460V vital buses; and A, B, & C 125V distribution cabinets). The 84' corridor is also directly above the 4160V vital switchgear rooms (64' elevation). The 4160V switchgear rooms contain redundant safe shutdown equipment (A, B, & C 4160V vital buses) and the C 125VDC batteries. The equipment drains in the 84' corridor also represent a potential steam flooding concern to the 460V switchgear rooms, 4160V switchgear rooms, and RHR pump rooms (dependent on actual drain pipe routing) due to the lack of installed equipment drain check valves in these rooms. In addition, the inspectors questioned whether portions of the above mentioned high energy piping met the design criteria for encapsulation sleeves as described in UFSAR Section 3.6.5.11 (a Unit 2 design basis pipe break concern only).

5Enclosure

(2) UFSAR Section 3.6.5.13 states, in part, "Investigations have been made as to thecapability of operation of Class I (seismic) equipment in the event of a failure of non-Class I (seismic) equipment which would cause flooding due to tank rupture. The monitor tanks are not diked, but the failure of any of these tanks would not cause flooding serious enough to prevent Class I (seismic) safety-related equipment from operating satisfactorily. A similar investigation showed that equipment arrangement and floor drainage systems design are adequate to prevent flooding in the event of a non-Class I (seismic) pipe rupture serious enough to prevent safeguards systems from operating satisfactorily." The inspectors noted that there appears to be several non-seismic piping systems in the auxiliary building 84' corridor adjacent to the Unit 1 & 2 460V vital switchgear rooms. The inspectors found no engineering evaluation (flooding analysis) to ensure that the rupture of these non-seismic piping systems during a seismic event would not prevent Class I (seismic) safety-related equipment from operating satisfactorily. Specifically, these non-seismic piping systems represent a significant internal flood vulnerability to the vital switchgear rooms (460V & 4160V) and RHR pump rooms given the existing minimal flooding barriers, no apparent flood detection, and interconnected equipment drain system.(3) The inspectors noted that there are no equipment drain check valves installed in the64' 4160V vital switchgear rooms. The inspectors found no engineering evaluation (flooding analysis) to ensure that the rupture of non-seismic tanks and/or piping systems (located at and above 64' elevation in the auxiliary building) during a seismic event would not prevent Class I (seismic) safety-related equipment in the 4160V vital switchgear rooms from operating satisfactorily.

(4) The inspectors noted that there are no equipment drain check valves installed in theRHR pump rooms and that the drain system appears to be interconnected (drain water above the 45' elevation can flow to both RHR pump room sumps). The inspectors found no engineering evaluation (flooding analysis) to ensure that the rupture of non-seismic tanks and/or piping systems (located at and above 45' elevation in the auxiliary building)during a seismic event would not result in flooding out both RHR pump rooms concurrently. For example, a rupture of the monitor tanks on 64' elevation may result in concurrently flooding both RHR pump rooms.(5) The inspectors noted that there are no equipment drains, no flood detection, and nowatertight doors in the 84' area containing the two redundant safety-related diesel fuel oil transfer pumps (FOTPs). The inspectors found no engineering evaluation (flooding analysis) to ensure that the rupture of non-seismic tanks and/or piping systems (located in, adjacent to, or above this area) following a seismic-induced loss of offsite power event would not prevent Class I (seismic) safety-related equipment from operating satisfactorily. Specifically, flood damage to both FOTPs (given that the FOTP motors are located only inches off the 84'elevation floor) and subsequent failure of all three redundant emergency diesel generators (following consumption of the limited fuel oil supply in their respective day tanks).The inspectors discussed the above concerns with PSEG engineering on severaloccasions during the inspection period. On February 8, 2007, engineering initiated corrective action notification (NOTF) 20312851 to evaluate the NRC inspectors' flooding 6Enclosure questions and concerns. PSEG's evaluation of NOTF 20312851 was still in progress atthe end of the inspection period. The inspectors determined that Salem's potential vulnerabilities to internal flooding willbe treated as an unresolved item (URI), pending completion of a technical evaluation by PSEG. An unresolved item is an issue requiring further information to determine if it is acceptable, if it is a finding, or if it constitutes a deviation or violation of NRC requirements. In this case, additional NRC review will be required to independently assess PSEG's technical evaluation of the above concerns relative to PSEG's design and licensing bases. Specifically, the NRC will assess whether PSEG adequately implemented design control measures to ensure the capability of operation of Class I (seismic) equipment in the event of a failure of non-Class I equipment in the auxiliarybuilding. (URI 05000272&311/2007002-01, Potential Vulnerabilit ies to InternalFlooding)

1R11 Licensed Operator Requalification Program

Main article: IP 71111.11Q

a. Inspection Scope

(1 sample)The inspectors observed a simulator training scenario conducted on February 20, 2007,to assess operator performance and training effectiveness. The scenario involved a loss of generator stator cooling and a component cooling (CC) water leak in containment that required operators to manually trip the simulated plant. The inspectors verified operator actions were consistent with operating, alarm response, abnormal, and emergency procedures. The inspectors assessed simulator fidelity and verified that evaluators identified deficient operator performance where appropriate. The inspectors observed the simulator instructors' critique of operator performance. Documents reviewed are listed in the attachment.

b. Findings

No findings of significance were identified.

1R12 Maintenance Effectiveness (71111.12)

a. Inspection Scope

(2 samples)The inspectors reviewed performance monitoring and maintenance effectiveness issuesfor components and systems. The inspectors assessed whether PSEG was adequately monitoring equipment performance to ensure that preventive maintenance was effective. The inspectors verified that the components were monitored in accordance with the maintenance rule program requirements. The inspectors compared documented functional failure determinations and unavailability hours to those being tracked by PSEG to evaluate the effectiveness of PSEG's condition monitoring activities and to determine whether performance goals were being met. The inspectors reviewed applicable work orders, corrective action notifications, and preventive maintenance tasks. Documents reviewed are listed in the attachment. The following two samples were completed:

7Enclosure Unit 1 15 service water pumpUnit 2 turbine driven auxiliary feedwater (TDAFW) pump

b. Findings

Green. A self-revealing non-cited violation of 10 CFR 50, Appendix B, Criterion V,"Instructions, Procedures, and Drawings," was identified for failure to conduct maintenance in accordance with appropriate written procedures.Description: Between November 27 and December 2, 2006, PSEG personnel replacedthe 15 service water pump (SWP) shaft sleeve and pump packing under work order 30002817. On December 2, the 15 SWP was started to break-in and adjust the new packing. While the 15 SWP was running the shaft sleeve and packing overheated, damaging the 15 SWP. The 15 SWP was repaired and returned to service on December 7, 2006.PSEG entered this issue into the corrective action program as NOTF 20306266,completed corrective maintenance under the original work order, and evaluated the issue under work order 70064075. PSEG determined that the damage was caused by inadequate cooling of the packing. The packing did not receive sufficient cooling because the leak-off line was clogged with accumulated sediment from the Delaware River and because external cooling was not applied during initial break-in. The leak-off line provides cooling to the packing by allowing a small amount of service water to flow past the installed carbon bushing and up to the packing. In the process of performing the post maintenance test, the stuffing box overheated and the shaft sleeve seized to the stuffing box bearing, in turn causing the bearing to spin in the stuffing box bearing seat. Examination of the packing, shaft sleeve, and the stuffing box revealed that the shaft sleeve was marked and discolored from the packing overheating the shaft sleeve and the carbon bushing in the bottom of the stuffing box appeared to have melted. The post-maintenance test procedure for the pump is Section 5.7 of SC.MD-EU.SW-0002, Johnston Service Water Pump Removal and Installation. Stuffing box temperature measurements are recorded per procedure, and the pump must be stopped if stuffing box temperatures reach 180F. PSEG determined that there wasinadequate external cooling applied to the pump stuffing box during pump packing break in. The procedure notes that inadequate leakage and lubrication will burn packing and damage shafts and sleeves. It also notes that leakage should be free flowing, and that external cooling water should be available when adjusting packing. PSEG determined that this procedural guidance was vague, and led to the significant damage to the pump shaft sleeve and stuffing box. According to control room logs, the 15 Service Water Pump was run for fourteen minutes prior to being stopped for packing concerns. Based on the damage observed when the pump was inspected, actual stuffing box temperature exceeded 180F before the pump was stopped. The pump was returned to themaintenance shop for rework, and five additional days of unavailability were accrued due to pump damage resulting from the improper post maintenance test.Analysis: The inspectors determined that overheating of the 15 SWP shaft sleeve andpacking following maintenance was a performance deficiency that caused 129 hours0.00149 days 0.0358 hours 2.132936e-4 weeks 4.90845e-5 months of 8Enclosure unavailability following the attempt to break-in the 15 SWP packing on December 2,2006. The finding is more than minor because it impacted the Mitigating Systems cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, incorrectly performed maintenance reduced the availability of the 15 SWP. In accordance with IMC 0609, Appendix A, "Significance Determination of Reactor Inspection Findings for At-Power Situations," the inspectors conducted a Phase 1 screen and determined that this finding required a Phase 2 analysis because both the Initiating Event and Mitigating Systems Cornerstones were adversely impacted by the 15 SWP unavailability. Because the Risk-Informed Notebook for Salem Generating Station does not contain a Loss of Service Water worksheet, the Senior Reactor Analyst (SRA) performed a Phase 3 risk assessment using the Salem Standardized Plant Analysis Risk (SPAR) model.Consistent with the inspector's estimate of 129 hours0.00149 days 0.0358 hours 2.132936e-4 weeks 4.90845e-5 months of additional 15 SWPunavailability, the SRA used an exposure time of 129 hours0.00149 days 0.0358 hours 2.132936e-4 weeks 4.90845e-5 months to model this additional unavailability time interval and set the 15 SWP Test and Maintenance basic event (SWS-MDP-TM-1SWE5) to TRUE. The estimated increase in annualized core damage frequency for this condition was low E-9, or very low risk significance (Green). The dominant core damage sequences involved the loss of service water initiating events with subsequent operator failure to maintain adequate reactor coolant pump (RCP) seal cooling and resultant RCP seal failure.The performance deficiency has a cross-cutting aspect in the area of humanperformance because PSEG did not effectively communicate human error prevention techniques. Maintenance technicians assigned to perform the post maintenance test were unfamiliar with the task. The pre-job brief did not discuss in detail the application of external cooling water to the packing gland during packing break in. At the job site, maintenance technicians proceeded with the post maintenance test in the face of uncertainty, resulting in equipment damage.Enforcement: 10 CFR 50, Appendix B, Criterion V, "Instructions, Procedures, andDrawings," requires, in part, that activities affecting quality shall be accomplished in accordance with documented instructions, procedures, or drawings, of a type appropriate to the circumstances. Section 5.7 of the Johnston Service Water Pump Removal and Installation procedure specifies actions to prevent heat damage to the pump during the packing run in. Contrary to the above, damage to the pump shows that the 15 service water pump was running with inadequate cooling flow to the packing and bushing, allowing gland temperature to exceed the 180F limit specified in theprocedure for pump shutdown.

As a result, the 15 SWP was rendered inoperable for 129 hours0.00149 days 0.0358 hours 2.132936e-4 weeks 4.90845e-5 months , starting on December 2, 2006. Because this finding is of very low safety significance, and has been entered into the corrective action program in NOTF 20306266, this violation is being treated as a NCV, consistent with section VI.A of theNRC Enforcement Policy. (NCV 05000272/2007002-02, 15 Service Water PumpUnavailability)9Enclosure

1R13 Maintenance Risk Assessments and Emergent Work Control

Main article: IP 71111.13

a. Inspection Scope

(7 samples)The inspectors reviewed seven maintenance activities to verify that the appropriate riskassessments were performed as required by 10 CFR 50.65(a)(4) prior to removing equipment for work. The inspectors reviewed the applicable risk evaluations, work schedules and control room logs for these configurations to verify that concurrent planned and emergent maintenance and test activities did not adversely affect the plant risk already incurred with these configurations. PSEG's risk management actions were reviewed during shift turnover meetings, control room tours, and plant walkdowns. The inspectors also used PSEG's on-line risk monitor (Equipment Out-Of-Service workstation) to gain insights into the risk associated with these plant configurations.

Finally, the inspectors reviewed notifications documenting problems associated with risk assessments and emergent work evaluations. Documents reviewed are listed in the attachment. The following plant configurations were assessed: *Planned maintenance on the 22 containment fan coil unit (CFCU), the 24 servicewater (SW) pump, the number 1 station air compressor (SAC), and the 22 chiller concurrently*Planned maintenance on the number 1 emergency control air compressor(ECAC), the number 1 SAC and the number 11 station power transformer (SPT)Emergent failure of the number 22 chiller concurrent with planned maintenanceon the number 23 service water (SW) pump and number 1 SACUnplanned maintenance on the number 2 250-VDC battery charger concurrentwith planned maintenance on the 23 auxiliary building ventilation exhaust fan, the 26 service water pump, and the number 1 SAC. Automatic operation of pressurizer pilot operated relief valve (PORV) 2PR2 was unavailable at the timePlanned maintenance on the 12 and 22 switchgear ventilation supply fanconcurrent with planned maintenance on the 1 SAC, extreme cold winter weather conditions, and painting in the Unit 1 chiller room. Automatic operation of pressurizer PORV 2PR2 was unavailable at the timePlanned maintenance on the station blackout (SBO) air compressor (a yellowrisk condition for both units)Unplanned 12SW23 service water valve inoperability. 12SW23 was manuallyopened following the failure to close automatically.

b. Findings

No findings of significance were identified.

1R15 Operability Evaluations (71111.15)

a. Inspection Scope

(7 samples)The inspectors reviewed seven operability determinations for degraded or non-conforming conditions associated with:

10Enclosure *NOTFs 20308265 and 20308301, operability of the Salem unit 1 and 2 auxiliarybuilding ventilation (ABV) system with the ABV supply fan inlet guide vanes disabled during installation of an ABV permanent modification*NOTF 20310615, operability of the Salem unit 1 and unit 2 service watersystems during a period of abnormally low tide on January 19, 2007*NOTF 20310248, operability of the 13 containment fan coil unit (CFCU) followinga failure to start in slow speed during weekly high flow flush of the service water cooling coils*NOTFs 20312989 and 20313029, operability of Salem unit 2 containmentfollowing isolation of component cooling (CC) water to the excess letdown heat exchanger in response to failed open CC relief valve 2CC112 and loss of indication for CC containment isolation valve 2CC215*NOTF 20312512, operability of the unit 2 turbine driven auxiliary feedwater pump(23 AFW pump) following discovery that the turbine casing insulation was not installed*NOTF 20314620, operability of the 22 service water pump and strainer followingan overload trip of the strainer on February 24, 2007*NOTF 20314524, 22 service water (SW) strainer motor thermal overload tripThe inspectors reviewed the technical adequacy of the operability determinations toverify the conclusions were justified. The inspectors also walked down accessible equipment to corroborate the adequacy of PSEG's operability determinations.

Additionally, the inspectors reviewed other PSEG identified safety-related equipment deficiencies during this report period and assessed the adequacy of their operability screens. Notifications and documents reviewed are listed in the attachment.

b. Findings

No findings of significance were identified.

1R17 Permanent Plant Modifications (71111.17)

a. Inspection Scope

(1 sample)The inspectors reviewed permanent modifications to the Salem Unit 1 and Unit 2auxiliary building ventilation (ABV) supply fan control circuit under change numbers 80088621 and 80088622. This review included system walkdowns, interviews with plant engineers and operators, verification of simulator fidelity, and functional comparison of the new control scheme to the FSAR description. The inspectors also reviewed post modification testing.This modification replaced an operator work around by making it possible to preventautomatic start of both ABV supply fans on receipt of an engineered safeguards (SEC)signal. The ABV system is expected to operate in a manner that maintains a slight vacuum in the auxiliary building following an accident. This ensures that any leakage is contained in the auxiliary building. Salem postulated an accident condition under which the auxiliary building would become pressurized and allow leakage to escape the auxiliary building. In response, Salem disabled automatic start of a single ABV supply 11Enclosure fan by deenergizing control power and taking other administrative actions. However, theoperator actions needed to restore the disabled ABV supply fan to service were a significant operator work around. Therefore, Salem modified the ABV supply fan control circuitry to permit operators to control ABV supply fan configuration remotely from the control room requiring only minimal operator action.

b. Findings

No findings of significance were identified.

1R19 Post-Maintenance Testing (71111.19)

a. Inspection Scope

(7 samples)The inspectors observed portions of and/or reviewed results of seven post-maintenancetest activities for the following equipment:*Work order (WO) 60059304 and 60036717, repair of body-to-bonnet leakagefrom spent fuel pump discharge valves 11SF68 and 12SF68*WO 30100378, 1 emergency control air compressor (ECAC) cleaning andcalibration of alarm and trip switches*WO 30100170, 22 chiller condenser heat exchanger internal inspection and leakrepair*WO 60029010, upgrade of Unit 2 main condenser air ejector radiation monitor2R15 per DCP 80045601*WO 60029010, upgrade Unit 2 condenser air ejector radiation monitor 2R15

WO 60067562, replacement of 2CV141, 23 positive displacement chargingpump discharge relief valve*WO 60067650, retest of containment fan cooler unit service water valvesThe inspectors assessed whether:

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

(2) testing was adequate for the maintenance performed;

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

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

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

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

b. Findings

No findings of significance were identified.

1R22 Surveillance Testing (71111.22)

a. Inspection Scope

(7 samples)The inspectors observed portions of and/or reviewed results for seven surveillance teststo verify, as appropriate, whether the applicable system requirements for operability 12Enclosure were adequately incorporated into the procedures and that test acceptance criteria wereconsistent with procedure requirements, the Technical Specification requirements, the Updated Final Safety Analysis Report (UFSAR), and ASME Section XI for pump and valve testing. Documents reviewed are listed in the attachment. The following surveillance tests were inspected:*Work order (WO) 50100886, Unit 1 SSPS Train A - reactor trip breaker UV coiland auto shunt trip*WO 50100948, 23 component cooling pump inservice testing

WO 50099941, 12 residual heat removal pump inservice testing

WO 50102373, Unit 1 control rod exercising to verify control rod operability

WO 50100783, 22 residual heat removal pump discharge check valve closure

WO 50090169, 1B diesel generator endurance run

S1.OP-ST.RC-0008, reactor coolant system water inventory balance

b. Findings

No findings of significance were identified.Cornerstone: Emergency Preparedness [EP]1EP2Alert and Notification System (ANS) Testing (71114.02)

a. Inspection Scope

(1 sample)An onsite review was conducted to assess the maintenance and testing of PSEG's ANS. During this inspection, the inspectors interviewed site EP staff responsible for implementation of the ANS testing and maintenance. Notifications (NOTFs) pertaining to the ANS were reviewed for causes, trends, and corrective actions. The inspectors further discussed with PSEG the new ANS system design and its benefits over the previous system. The inspectors reviewed PSEG's original ANS design report to ensure compliance with those commitments for system maintenance and testing. The inspectors toured both the Emergency Operations Facility (EOF) and the 911 center.

On March 28, 2007, the inspectors observed a silent test of the ANS. The inspection was conducted in accordance with NRC Inspection Procedure 71114, Attachment 2.

Planning standard, 10 CFR 50.47(b)(5) and the related requirements of 10 CFR 50, Appendix E were used as reference criteria.

b. Findings

No findings of significance were identified.1EP3Emergency Response Organization (ERO) Augmentation (71114.03)

a. Inspection Scope

(1 sample)A review of Salem/Hope Creek's ERO augmentation staffing requirements and theprocess for notifying the ERO was conducted. This was performed to ensure the readiness of key staff for responding to an event and to ensure timely facility activation.

13Enclosure The inspectors reviewed procedures, issue reports , and call-in drills associated with theERO notification system and drills. The inspectors interviewed personnel responsible for testing the ERO augmentation process. The inspectors compared qualification requirements to the training records for a sample of ERO members. The inspectors also verified that the EP department staff were receiving required training as specified in the emergency plan. The inspection was conducted in accordance with NRC Inspection Procedure 71114, Attachment 3. Planning standard, 10 CFR 50.47(b)(2) and related requirements of 10 CFR 50, Appendix E were used as reference criteria.

b. Findings

No findings of significance were identified.1EP4Emergency Action Level (EAL) and Emergency Plan Changes (71114.04)

a. Inspection Scope

(1 sample)Prior to this inspection, the NRC had received and acknowledged changes made to theSalem/Hope Creek Emergency Plan and implementing procedures. PSEG developed these changes in accordance with 10 CFR 50.54(q), and determined that the changes did not result in a decrease in effectiveness to the Plan. PSEG also determined that the Plan continued to meet the requirements of 10 CFR 50.47(b) and Appendix E to 10 CFR 50. During this inspection, the inspectors conducted a sampling review of Salem/Hope Creek's 10 CFR 50.54(q) screenings for the changes made to the Plan that could potentially result in a decrease in effectiveness. This review did not constitute NRC approval of the changes and, as such, the changes remain subject to future NRC inspection. Also, the NRC reviewed the licensee's EAL scheme for logic and consistency. The inspection was conducted in accordance with NRC Inspection Procedure 71114, Attachment 4. The requirements in 10 CFR 50.54(q) were used as reference criteria.

b. Findings

No findings of significance were identified.1EP5Correction of Emergency Preparedness Weaknesses and Deficiencies (71114.05)

a. Inspection Scope

(1 sample)The inspectors reviewed self-assessments and audit reports to assess PSEG's ability toevaluate their performance and programs. The inspectors reviewed NOTFs initiated from December 2005 to March 2007 at Salem/Hope Creek from drills, self-assessments, and audits. This inspection was conducted according to NRC Inspection Procedure 71114, Attachment 5. Planning standard, 10 CFR 50.47(b)(14) and the related requirements of 10 CFR 50, Appendix E were used as reference criteria.

b. Findings

No findings of significance were identified.

14Enclosure

1EP6 Drill Evaluation

Main article: IP 71114.06

a. Inspection Scope

(1 sample)The inspectors observed the annual state emergency preparedness exercise, conductedon March 20, 2007. The inspectors evaluated drill performance relative to developing proper classifications, notifications, and protective action recommendations by PSEG personnel. The inspectors reviewed the Salem Event Classification Guides and Emergency Plans to determine that classifications and notifications were in accordance with these documents. Drill performance was observed in the control room simulator and the EOF. The drill critique adequately captured deficiencies with drill performance.

The inspectors also verified that PSEG correctly counted the drill contribution in the NRC performance indicator for Drill/Exercise Performance.b.FindingsNo findings of significance were identified.2.RADIATION SAFETYCornerstone: Occupational Radiation Safety [OS]2OS1Access Control to Radiologically Significant Areas (71121.01)

a. Inspection Scope

(7 samples)The inspectors reviewed all PSEG performance indicators (PI) for the OccupationalExposure Cornerstone for followup. PSEG has had no PI events in this cornerstone in the past 4 quarters.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 that:prescribed radiation work permits, procedure, and engineering controls were in place, PSEG surveys and postings were complete and accurate, and air samplers were properly located.The inspectors examined PSEG's physical and programmatic controls for highlyactivated or contaminated materials (non-fuel) stored within spent fuel and other storage

pools.The inspectors discussed with the Radiation Protection Manager high dose rate - highradiation areas, and very high radiation areas (VHRA) controls and procedures. The inspectors verified that any changes to PSEG procedures do not substantially reduce the effectiveness and level of worker protection.

15Enclosure The inspectors discussed with first-line health physics supervisors the controls in placefor special areas that have the potential to become VHRA during certain plant operations. The inspectors determined that these plant operations require communication beforehand with the radiation protection group, so as to allow corresponding timely actions to properly post and control the radiation hazards.The inspectors reviewed and assessed the adequacy of PSEG's internal doseassessment for any actual internal exposure greater than 50 mrem Committed Effective Dose Equivalent (CEDE).During the week of February 5, 2007, the inspectors made direct observations ofradiologically significant work taking place in the primary auxiliary building. Activities observed included changing out of a reactor coolant filter and maintenance work on the 22 RHR system.

b. Findings

No findings of significance were identified.2OS2ALARA Planning and Controls (71121.02)

a. Inspection Scope

(4 samples)Utilizing PSEG records, the inspectors reviewed the historical trends and current statusof tracked plant source terms. The inspectors determined that PSEG was making allowances or developing contingency plans for expected changes in the source term due to changes in plant fuel performance issues or changes in plant primary chemistry.

The inspectors focused on the upcoming Unit 1 refueling outage planning, including the basis for outage estimates, ALARA reviews, and revisions to radiation protection technician job guides.The inspectors determined that there have been declared pregnant workers during thecurrent assessment period. The inspectors reviewed the exposure results and monitoring controls employed by PSEG with respect to requirements of 10 CFR 20. A total of six personnel were declared pregnant workers during 2006, with the maximum dose during the declaration period being 3 millirem.The inspectors reviewed PSEG's exposure tracking system. The inspectors determinedthat the level of exposure tracking detail, exposure report timeliness and exposure report distribution was sufficient to support control of collective exposures.The inspectors determined that work activity planning includes consideration of thebenefits of dose rate reduction activities such as shielding provided by water filled components/piping, job scheduling, and shielding and scaffolding installation and removal activities.

b. Findings

No findings of significance were identified.

16Enclosure 2OS3Radiation Monitoring Instrumentation and Protective Equipment (71121.03)

a. Inspection Scope

(1 sample)The inspectors reviewed corrective action program for NOTFs related to exposuresignificant radiological incidents that involved radiation monitoring instrument deficiencies since the last inspection in this area. No NOTFs of this type were identified.The inspectors reviewed the most recent National Voluntary Laboratory AccreditationProgram (NVLAP) audit and dosimeter performance for the vendor laboratory utilized by PSEG to determine dose of record. The inspectors also reviewed the system calibration and periodic system checks for the licensee's whole body counter.

b. Findings

No findings of significance were identified.

OTHER ACTIVITIES

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

a. Inspection Scope

Cornerstone: Mitigating Systems (2 samples)Safety System Functional Failures (Unit 1 and 2)The inspectors reviewed all Salem Unit 1 and 2 licensee event reports issued from thefour calendar quarters of 2006 for safety system functional failures as defined by NEI 99-02, "Regulatory Assessment Performance Indicator Guideline," Revision 4.Cornerstone: Barrier Integrity (4 samples)The inspectors sampled PSEG submittals for two PIs listed below for Salem Unit 1 and2. For both PIs, the inspectors reviewed the period from the four calendar quarters of 2006. To verify the accuracy of the PI data reported during that period, PI definitions and guidance contained in NEI 99-02, "Regulatory Assessment Performance Indicator Guideline," Revision 4, were used to verify the basis in reporting for each data element.Reactor Coolant System (RCS) Identified Leak Rate RCS Specific ActivityThe inspectors reviewed main control room logs and were familiar with identified leakrate data through plant status reviews required by NRC Inspection Manual Chapter 2515, Appendix D, "Plant Status."

17Enclosure Cornerstone: Emergency Preparedness (3 samples)Drill and Exercise PerformanceERO Drill ParticipationAlert and Notification System ReliabilityThe inspectors reviewed supporting documentation from drills and tests in all quarters of2006 to verify the accuracy of the reported data. The review of these PIs was conducted in accordance with NRC Inspection Procedure 71151. The acceptance criteria used for the review were 10 CFR 50.9 and NEI 99-02, Revision 4, "Regulatory Assessment Performance Indicator Guidelines."b.Findings No findings of significance were identified.4OA2Identification and Resolution of Problems (71152).1Review of Items Entered into the Corrective Action Program:As required by Inspection Procedure 71152, Identification and Resolution of Problems,and in order to help identify repetitive equipment failures or specific human performance issues for follow-up, the inspectors performed a daily screening of all items entered into PSEG's corrective action program. This was accomplished by reviewing the description of each new notification and attending daily management review committee meetings.

Documents reviewed are listed in the attachment.4OA5Other Activities.1(Closed) Unresolved Item (URI)05000272/2003006-02 a. Inspection Background and Scope (71153)BackgroundNRC Special Inspection Report No. 05000272/2003006; and 05000311/2003006, datedOctober 15, 2003, (ADAMS Accession No. ML032890212) described, in Section 4OA3.4, a condition involving through-wall leakage from the Unit 1 spent fuel pool (SFP) that resulted in onsite groundwater contamination. The circumstances surrounding the leakage, and the onsite ground water contamination, were further described in NRC Information Notice No. 2004-05: "Spent Fuel Pool Leakage to Onsite Groundwater," dated March 3, 2004 (ADAMS Accession No. ML040580454). During the inspection of this matter, an unresolved item (URI 05000272/2003006-02) was identified relative to evaluation of the potential effect of through-wall leakage on the reinforced concrete SFP structure. In response to the through-wall leakage, PSEG conducted a prompt review thatindicated there was no immediate safety concern associated with the structural integrity of the SFP structure. Notwithstanding, PSEG initiated both a short-term and long-term 18Enclosure investigation to throughly evaluate any potential negative impact of the leakage on thefuel pool structure and its design margins. PSEG obtained contractor technical support for this effort. Subsequently, PSEG's contractor conducted extensive testing of representative samples of concrete and steel rebar to evaluate potential impact of boric acid water leakage on the structure. The testing included submersion testing of concrete samples and the incorporated steel rebar, and evaluation of potential loss of structural design margins. In February 2006, NRC staff met onsite with PSEG and contractor staff, toured thestructure, and examined PSEG's assessment of the integrity of the SFP structure. The NRC concluded this matter did not represent an immediate or near-term safety concern.

However, the NRC identified additional information that was needed for NRC to resolve the long-term aspects of this matter, establish a conclusion on the long-term structural integrity of the spent fuel pool, and close the unresolved item. NRC subsequently posed questions to PSEG to obtain additional information to support NRC evaluation and closure of the URI. The questions posed, and PSEG's responses are available at ADAMS Accession No. ML071080125. This Accession Number also includes PSEG's summary of its bases for concluding the SFP structure will remain sound and discusses

concrete test results. Inspection ScopeThe NRC inspectors conducted an onsite inspection on February 28 and March 1, 2007to review PSEG's responses to the questions provided. The NRC inspectors conductedindependent visual observations of the Unit 1 and Unit 2 SFP structure; reviewed test data and test results, and reviewed SFP structure design margin evaluations. In addition, the NRC inspectors reviewed PSEG's plans for ongoing monitoring of the structure relative to applicable industry standards; and evaluated collection and management of leakage. Further, on March 21, 2007, an NRC inspector observed PSEG's set-up and in-situ testing of the compressive strength of portions of the Unit 1 spent fuel storage pool wall. The NRC inspectors also reviewed the results of the testing. PSEG tested and evaluated the effects of boric acid on the SFP structures. The testingand evaluation was conducted in a phased approach. Short-term testing of potential boric acid degradation of concrete was initially conducted to identify potential near term degradation. These tests and evaluations were followed by longer term testing to evaluate potential long-term structural degradation. The testing included laboratory testing of boric acid solution degradation on concrete and steel rebar by use of representative boric acid solutions. PSEG also conducted SFP structural evaluations, per applicable industry standards (ACI 340.3R-02), and initiated long-term, ongoing monitoring of the spent fuel pool structures in accordance with this industry standard.

PSEG's evaluations did not identify any indications of surface deterioration due to reinforcing steel corrosion and did not identify significant loss of design margin over the life of the facility. PSEG's test results indicated the structure would meet its design margins over the life of the facility including the expected time duration if the facility's operating licenses were renewed. Documents reviewed are listed in the attachment.

b. Findings

No findings of significance were identified. 4OA6Meetings, Including ExitOn April 5, 2007, the resident inspectors presented the inspection results to Messrs.Joyce and Fricker. None of the information reviewed by the inspectors was considered proprietary.ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee personnel

T. Joyce, Station Vice President

C. Fricker, Plant Manager

R. Gary, Radiation Protection Manager

D. Denelsbeck, Radiation Protection Supervisor

A. Johns, Radiation Protection Supervisor

T. Neufang, Radiological Engineering Manager

D. Burgin, Empergency Preparedness Manager

E. Villar, Regulatory Assurance Engineer

T. Mulholland, Spent Fuel Cooling System Manager

A. Johnson, Salem Mechanical/Structural Design Manager

L. Rajhonshi, Senior Manager Design Engineering

T. Roberts, Manager, Engineering Programs

J. Russell, Site Dosimetry

M. Gwirtz, Operations Director

H. Berrick, Licensing Engineer

J. Duffy, Design Engineer

J. Stone, Maintenance Director

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened05000272&311/2007002-01URIPotential vulnerabilities to internal flooding(Section 1R06)

Opened/Closed

05000272/2007002-02NCV15 service water pump unavailability(Section 1R12)

Closed

05000272/FIN-2003006-02URINRC to review results of Unit 1 spent fuelpool structural analysis (Section 4OA5.1)

Discussed

None

A-2Attachment

LIST OF DOCUMENTS REVIEWED

In addition to the documents identified in the body of this report, the inspectors reviewed thefollowing documents and records:Section 1R01: Adverse Weather ProtectionProceduresWC-AA-107, Seasonal Readiness, Rev. 2SC.OP-AB.ZZ-0001, Adverse Environmental Conditions, Rev. 9Drawings208997, 211612

Notifications20311039,

20311315,

20311896,

20312388,

20311050,

20105467,

20114366,

20310774,20312408,

20313500,

20313690,

20313265,

20312507,

20315710, 20315710Orders60030865,

80052059, 80091607

Other Documents2007 Salem Grassing Seasonal Readiness AffirmationSalem Generating Station Event Classification GuideSection 1R04: Equipment AlignmentProceduresS2.OP-SO.CVC-0001, Charging, Letdown, and Seal Injection, Rev. 29S2.OP-SO.CVC-0002, Charging Pump Operation, Rev. 34

S2.OP-SO.CVC-0006, Boron Concentration Control, Rev. 20

S1.FP-PM.FS-0019, Non Class I CO

System Flow Path Verification, Rev. 0S1.OP-AB.SW-0001, Loss of Service Water Header Pressure, Rev. 15

S1.OP-SO.SW-0005, Service Water System Operation, Rev. 35

S1.OP-ST.SW-0013, Service Water Valve Verification Modes 1-4, Rev. 1

S2.OP-SO.AF-0001(Q), Auxiliary Feedwater System operation, Rev. 27

S2.OP-ST.AF-0008(Q), Auxiliary Feedwater Valve Verification Modes 1-3, Rev. 4

S2.OP-ST.AF-0009(Q), Plant systems - Auxiliary Feedwater, Rev. 22

S2.OP-ST.AF-0011(Q), Auxiliary Feedwater Alternate Suction Source Verification Moses 1-3,Rev. 2S2.OP-ST.AF-0012(Q), Auxiliary Feedwater Spool Piece Verification, Rev. 1Drawings205235,

205242,

205335,

205336,

207533,

229953,

239097,

205336,

600256,

600257, 600891Completed SurveillancesS1.OP-ST.SW-0013, Service Water Valve Verification Modes 1-4, Rev. 1, dated 1/27/04

A-3Attachment Notifications20230859,

20308442,

20289724,

20287566,

20272406,

20265966,

20261079,

20243927,20246647,

20256857,

20305194,

20304857,

20304397,

20299531,

20299044, 20302899,

256957,

20310939,

20311083,

20311117,

20311183,

20311335,

20311382, 20311427,

20311430,

20311477,

20311563,

20311740,

20311748,

20309766,

20309770, 20309824,

20309825,

20267659,

20267664,

20276514,

20316073,

20316110,

20316124, 20314496Orders80089441,

80089591,

60068282,

70055420, 70046101

Other DocumentsWCD 4193005PSEG Nuclear LLC letter

LR-N06-2006, dated April 13, 2006, to the NRC

DE-CB.SW-0047, Configuration Baseline Documentation for Service Water System, Rev. 6

Risk-Informed Inspection Notebook for Salem Generating Station, Rev. 2

Salem Inservice Testing Program Basis - Service Water Valves, Rev. 8

SGS Unit 1 PRA Risk Evaluation Form for Work Week No. 011, Rev. 1 (3/11/07 - 3/17/07)

Technical Specification 3.7.4.1, Service Water System Updated Final Safety Analysis Report, Section 9.2.1, Service Water System Lineup ID 942

Lineup ID 918

Section 1R05: Fire ProtectionProceduresPre-Fire Plan

FRS-II-511, U1 & U2 Electrical Penetration Area, Elevation: 78' - 0"Pre-Fire Plan

FRS-II-512, Rev 2, U1 & U2 Mechanical Piping Penetration Area, Elevations 78' &

100'Pre-Fire Plan

FRS-III-815, Salem Fire/Fresh Water Pump HousePre-Fire Plan

FRS-III-821, Salem Station Black-Out Air compressor Building Salem - Unit 1, (Unit 2) Pre-Fire Plan

FRS-II-444, Demineralized Ion Exchanger Area, Rev. 3

Salem Pre-Fire Plan

FRS-III-818, Unit 3 Jet - Combustion Turbine, Rev. 3

SC.OP-AP.ZZ-0108 Attachment 11, Post-Fire Safe Shutdown Equipment - AdministrativeControls, Rev. 11SC.FP-SV.ZZ-0058, Inspection of Class 1 Fire Doors and Safety Related Areas for TransientCombustibles, Rev. 9SC.FP-AP.ZZ-0003, Actions for Inoperable Fire Protection - Salem Station, Rev. 11

NC.FP-TI.ZZ-0402, Inspection and Maintenance of SCBA, Rev. 0

NC.NA-AP.ZZ-0045, Respiratory Protection Program, Rev. 6

SC.FP-SV.FBR-0026, Flood and Fire Barrier Penetration Seal Inspection, Rev 3FRS-II-912, Pre-Fire Plan Salem Common Service Water Pipe Trench & Tunnel, Rev. 2

SC.FP-SV.FBR-0026 (Q), Flood and Fire Barrier Penetration Seal Inspection, Rev. 3Notifications20311158,

20311352,

20311358,

20311487,

20312090,

20312125,

20315110,

20315151,20314657,

20315580,

20315668,

20315674,

20315740

A-4Attachment Orders 60067007Other DocumentsSalem and Hope Creek Fire Impairment Log Book, dated 1/31/07Fire Drill Title UADS5013107, Salem Unit 1 Turbine Building Elevation 88

Section 1R06: Flood Protection MeasuresProceduresS2.OP-AB.COND-0001, Loss of

COND VAC, Rev. 12S2.OP-AB.CW-0001, Circulating Water System Malfunction, Rev. 25

S2.OP-AR.ZZ-0007 G-43, TURB Area LVL Hi PMP Start, Rev. 39

S1.OP-AB.ZZ-0002, Flooding, Rev. 2

S2.OP-AB.ZZ-0002, Flooding, Rev. 2

SC.FP-SV.FBR-0026, Flood and Fire Barrier Penetration Seal Inspection, Rev. 3

SC.OP-AP.ZZ-0108 Section 11, Salem HELB Criteria, Rev. 11Drawings205223 (SH 1-3), No. 1 Unit Building & Equipment Drains - Conventional, Rev. 33, 37, &

40205323 (SH 1-3), No. 2 Unit Building & Equipment Drains - Conventional, Rev. 35, 25, & 39

205226 SH 1 & 2, No. 1 Unit Floor Drains - Contaminated, Rev. 34 & 30

205326 SH 1 & 2, No. 2 Unit Floor Drains - Contaminated, Rev. 27 & 23

205227 SH 2, No. 1 Unit Equipment Vents & Drains - Contaminated, Rev. 23

205327 SH 2, No. 2 Unit Equipment Vents & Drains - Contaminated, Rev. 18Evaluations70035088,

70035399,

70042667, 70050702S-C-A900-MEE-0158

S-C-BD-MEE-0554-0Notifications20169101,

20253937,

20303649,

20311133,

20311171,

20311172,

20311689,

20312386,20312391,

20312396,

20312451,

20312777,

20312827,

20312851,

20313927, 20314684,

20314731,

20314827, 20315096Operating Experience

NRC Information Notice 83-44, Supplement 1: Potential Damage to Redundant SafetyEquipment as a Result of Backflow Through the Equipment and Floor Drain System, dated 8/30/90NRC Information Notice 2005-30: Safe Shutdown Potentially Challenged By UnanalyzedInternal Flooding Events and Inadequate Design, dated 11/7/05 Other DocumentsVTD

327743, Penetration Seal Inspection, dated 4/17/93, 10/02/94, 4/10/96, 5/12/97, 3/30/99,1/8/01

Salem Generating Station Individual Plant Examination, dated July 1993

A-5Attachment

==Section 1R07: Heat Sink PerformanceNotifications20314772,

20314842, 20315231Section 1R11: Licensed Operator Requalification ProgramProceduresS2.OP-PT.GEN-0003, Main Generator Stator Temperatures, Rev. 9S2.OP-AB.CC-0001, Component Cooling Abnormality, Rev. 11==

2-EOP-Trip-1, Reactor Trip or Safety Injection, Rev. 26Drawings 205331

Other DocumentsSimulator Scenario Guide S-ESG-0701, Normal Ops and a Loss of CCW/Reactor Trip, Rev. 1

Section 1R12: Maintenance EffectivenessProceduresSC.MD-CM.SW-0008, Service Water Pump Headshaft Sleeve Replacement, Rev. 2SC.MD-CM.SW-0006, Johnston Service Water Pump Inspection and Repair, Rev. 9

SH.MD-GP.ZZ-0008, Installation and Removal of Motors, Rev. 10

SC.MD-EU.SW-0002, Johnston Service Water Pump Removal and Installation, Rev. 17

SC.ER-DG.ZZ-0002, System Function Level Maintenance Rule Scoping VS. Risk Reference, Rev. 2

SC.ER-DG.ZZ-0003, Preventable and Repeat Preventable System Functional FailureDetermination, Rev. 0SC.MD-PM.AF-0003, 13 and 23 Auxiliary Feedwater Terry Turbine Disassembly, Inspectionand Reassembly, Rev. 10SC.MD-PM.AF-0004, 13 and 23 Turbine-Driven Auxiliary Feedwater Pump Disassembly,Inspection and Reassembly, Rev. 4S2.OP-ST.AF-0003, Inservice Testing - 23 Auxiliary Feedwater Pump, Rev. 43

S2.RA-ST.AF-0003, Inservice Testing 23 Auxiliary Feedwater Pump Acceptance Criteria, Rev.

17S2.OP-SO.AF-0001, Auxiliary Feedwater System Operation, Rev. 27 Completed SurveillancesS2.OP-ST.AF-0003, Inservice Testing - 23 Auxiliary Feedwater Pump, dated 9/8/06, 10/31/06,and 12/29/06Notifications20311128,

20311342,

20312163,

20312275,

20314620,

20310297,

20306266,

20305773,20292252,

20291947,

20291480,

20257957,

20256660,

20311719,

20307094, 20301999,

274829,

20274155,

20268361,

20316199,

20316264,

20316263,

20316262, 20291622

20001407,

20002429,

20162981,

20176252,

20180699,

20210118,

20220141, 20246051,

246604,

20248351,

20276816,

20277433,

20286674,

20287566,

20303033,

20303115,

A-6Attachment

20304799,

20310888,

20312163,

20312827,

20312835,

20314524,

20314686,

20314734,20314870,

20314877,

20315542, 20315803Evaluations70039419,

70062234,

70063198,

80089031, 80091603

Orders60067443,

30022817,

70064075,

80077339,

70037915,

70039048,

70054883,

70058084,60061351,

70054883,

70053248,

30003325,

30050996,

30091430,

60043335, 60058920Operating Experience

NRC Information Notice 94-84:

Air Entrainment in Terry Turbine Lubricating Oil System, dated12/2/94 PSEG Response to NRC Information Notice, dated 3/27/95Other DocumentsVTD

320202, Johnston Pump Drawing, Rev. 9VTD

320408, Technical Manual for Installation, Operation, and Maintenance of Johnston Pump Company 28 NMC - 3 Stage Service Water Pumps, Rev. 2

No. 23 TDAFW Pump Unavailability (Cumulus Database) through February 2007

MR PSFF Database, dated 2/27/07

PSEG Nuclear 10CFR 50.65 (a)(1) Goals, dated 2/27/07

S2AF - Auxiliary Feedwater Quarterly SHIP System Report, 4

th Qtr 2006S2AF - Auxiliary Feedwater Plant Health Committee System Presentation, 4

th Qtr 2006VTD No.

174547, Aux. Feed SystemSection 1R13: Maintenance Risk Assessments and Emergent Work ControlProceduresER-AA-600, Risk Management, Rev. 5ER-AA-600-1012, Risk Management Documentation, Rev. 6

S1.OP-SO.SW-0003, 12 Nuclear Service Water Header Outage, Rev. 25

S1.OP-SO.SW-0005, Service Water System Operation, Rev. 35Drawings205342 SH 5, SNGS No. 2 Unit Service Water Nuclear Area, Rev.

64205242, SH 1-7, Revs. 90, 84, 86, 76, 74, 83, 03 (respectively), No.1 Unit Service Water Nuclear AreaEvaluations

70061111

Notifications20310938,

20311844,

20311892,

20311894,

20312398,

20313022,

20314462,

20314696,20314712,

20267659,

20267664,

20276514,

20316073 ,

20316110, 20316124Orders60068282,

70055420

A-7Attachment Other DocumentsRisk-Informed Inspection Notebook For Salem Generating Station, Rev. 2WCDs

4193071 and 4192125

SGS Unit 2 PRA Risk Evaluation Form for work week number 007 (February 11 to 17, 2007)

SGS Unit 2 PRA Risk Evaluation Form for work week number 002 (January 7 to 13, 2007)

SGS Unit 1 PRA Risk Evaluation Form for work week number 003 (January 14 to 20, 2007)

Risk Management Documentation No.

SA-A4-2007-001, Refined Approach for Calculating Risk Associated with Block Valve 2PR7 Closure, Rev. 0

Risk-Informed Inspection Notebook For Salem Generating Station, Rev. 2

DE-CB.SW-0047, Configuration Baseline Documentation for Service Water System, Rev. 6

Risk-Informed Inspection Notebook for Salem Generating Station, Rev. 2

Salem Inservice Testing Program Basis - Service Water Valves, Rev. 8

SGS PRA System Notebook, Service Water System, Rev. 3

SGS Unit 1 PRA Risk Evaluation Form for work week number 011, Rev. 1 (March 11 to 17,

2007)

Techical Specification 3.7.4.1, Service Water System Updated Final Safety Analysis Report, Section 9.2.1, Service Water System Weekly Management Summary, Work Week 11 (3/11/07 - 3/17/07)

Section 1R15: Operability EvaluationsProceduresSC.OP-AP.ZZ-0108, Operability Assessment and Equipment Control Program, Rev. 11S2.OP-AB.CC-0001, Component Cooling Abnormality, Rev. 11

SC.OP-AP.ZZ-0108, Operability Assessment and Equipment Control Program, Rev. 11

S2.OP-SO.SW-0001, Service Water Pump Operation, Rev. 22

S2.OP-SO.SW-0005, Service Water System Operation, Rev. 38

SC.OP-SO.ZZ-0003, Component Biofouling, Rev. 1Evaluations

70058966

Drawings203575,

203577, 237957

Notifications20311308,

20311668,

20311724,

20311803,

20312069,

20308265,

20308301,

20310615,20307235,

20310248,

20313219,

20312989,

20312512,

20312180,

20314524, 20314620,

20315182, 20315317Orders70064694,

80088622,

70064846,

80088621,

70041288,

70064562,

70064871,

60067575,60066997,

70065677,

70065131, 60067986Other DocumentsS-C-AUX-MDC-0737, Loss of Ventilation During Station Blackout, Rev. 2S-2-ABV-MDC-2041, Salem Unit 2 Auxiliary Building Temperature Calculation - Normal andEmergency Modes, Rev. 1

A-8Attachment S-C-AF-MEE-1749, Effect of Loss of Room Cooler for Turbine Driven Auxiliary FeedwaterPump Room, Rev. 0S-C-AUX-MDC-0738, SBO - Mechanical Heat Loads in Turbine-Driven Auxiliary FeedwaterPump Rooms, Rev. 1ACM 07-012, S2SW -2SWE8 22 Service Water Strainer, dated 2/28/07

Section 1R17: Permanent Plant ModificationsProceduresSH.MD-SP.FBR-0001, Installation and Repair of Penetration Seals, Rev. 4SH.MD-SP.FBR-0002, Damming and Ceramic Fiber Seal Installation, Rev. 1

SH.MD-SP.FBR-0003, Installation and Repair of Silicone Foam Materials, Rev. 0Notifications20308308,

20309371,

20308772,

20309372,

20308265,

20308301, 20314748

Orders80088621,

80088622,

60063452,

60063453,

60063454,

60063455, 70064694

Section 1R22: Surveillance TestingProceduresS1.IC-ST.SSP-0010,

SSPS Train A-Reactor Trip Breaker UV Coil and Auto Shunt Trip, Rev. 14S2.OP-ST.CC-0003, Inservice Testing - 23 Component Cooling Pump, Rev. 20

S2.RA-ST.CC-0003, 23 Component Cooling Pump Surveillance Data Acceptance Criteria, Rev.

2S1.OP-ST.RHR-0002, Inservice Testing - 12 Residual Heat Removal Pump, Rev. 13

S1.RA-ST.RHR-0002, Inservice Testing 12 Residual Heat Removal Pump Acceptance Criteria,Rev. 6S1.OP-St.RCS-0001, Reactivity Control System Rod Control Assemblies, Rev. 18

S1.OP-ST.RC-0007, Seal Injection Flow, Rev. 5

S2.OP-ST.RHR-0002, Inservice Testing - 22 Residual Heat Removal Pump, Rev. 24

S1.OP-ST.DG-0002, 1B Diesel Generator Surveillance Test, Rev. 41

S1.RA-ST.DG-0002, 1B Diesel Generator Surveillance Test Acceptance Criteria, Rev. 4

S1.OP-ST.DG-0013, 1B Diesel Generator Endurance Run, Rev. 16

S1.OP-ST.RC-0008, Reactor Coolant System Water Inventory Balance, Rev. 19

S1.OP-AB.RC-0001, Reactor Coolant System Leak, Rev. 8Completed SurveillancesS1.OP-ST.RC-0008, Reactor Coolant System Water Inventory Balance, dated 2/23-27/07S1.OP-ST.DG-0012, 1A Diesel Generator Endurance Run, dated 2/27/07Drawings

205228

Notifications20311105,

20311818,

20312025,

20312334,

20310526,

20309710,

20309812,

20309791,20313153,

20312988,

20312958,

20312795,

20312779,

20315111,

20266883, 20314804,

20314940Orders50100886,

50100948,

30144736, 50100783

Evaluations

70052759

Other DocumentsDE-CB.RHR-0030, Configuration Baseline Documentation for the Residual Heat RemovalSystem, Rev. 4

Salem Inservice Testing Program Basis Data Sheets - Valves for 22RH8

VTD 106263, Crane Company 300 LB. Cast Alloy Steel Swing Check Valve, Rev. 6

A-10Attachment Section 1EP2: Alert and Notification System (ANS) EvaluationOther DocumentsFinal Rep - 10 Design Review ReportSiren Test Results from 2006 & 2007 (bi-weekly silent test & quarterly audible test)

Maintenance Records from November 2005

Section 1EP3: Emergency Response Organization (ERO) Staffing and AugmentationSystemOther DocumentsSalem/Hope Creek Emergency PlanERO Member RosterSection 1EP4: Emergency Action Level (EAL) and Emergency Plan ChangesOther DocumentsAll 50.54(q)

E-Plan and EAL changes from 2005 & 2006

Section 1EP5: Correction of Emergency Preparedness WeaknessesOther DocumentsLS-AA-120 "Issue Identification and Screening Process," Rev. 6LS-AA-125 "Corrective Action Program (CAP) Procedure," Rev. 11

All Issue Reports related to EP from 12/19/05 - 3/27/07

Drill Critique Reports - 2005 & 2006

50.54(t) Audits done by the Nuclear Oversight Committee (2006 & 2007)Orders70053308,

70053597,

70053973,

70054047, 70054318

Section 1EP6: Drill EvaluationOther DocumentsSalem - Self Evaluated Exercise, S07-072007 Tabletop Training Session Agenda and Timeline for

TSC - Salem Salem Generating Station Event Classification Guide Artificial Island Emergency Plan

NC.EP-EP.ZZ-0201, TSC - Integrated Engineering Response, Rev. 09Section 2OS1: Access Control to Radiologically Significant AreasProceduresRP-AA-220, Rev 3, Bioassay ProgramRP-AA-222, Rev 1, Methods for estimating Internal Exposure from In Vivo and In Vitro Bioassay Data

RP-AA-460, Rev 11, Controls for High and Very High Radiation Areas

RP-AA-460-1001, Rev 1, Additional High Radiation Exposure Controls

A-11Attachment

Section 2OS2: ALARA Planning and ControlsProceduresRP-AA-270, Rev 3, Prenatal Radiation ExposureRP-AA-400, Rev 4,

ALARA Program

RP-AA-1001, Rev 0, Establishing Collective radiation Exposure Estimates and Goals

RP-AA-401, Rev 7, Operational ALARA Planning and ControlsOther DocumentsRadiation Protection Job Guide:ISI Activities; Fuel Movement; Seal Table Room; UpperInternals Removal/Replacement for 1R18Fastscan Whole Body Counter:System Calibration, dated March 25, 2006; Co-60 and Cs-137 control chart for period 1/2/07 thru 2/6/07

Section 2OS3: Radiation Monitoring InstrumentationProceduresNVLAP Personnel Dosimetry Performance Testing Report for Global Dosimetry Solutions, Inc.,dated August 31, 2005

NVLAP On-Site Assessment of Global Dosimetry Solutions, Inc., dated April 20, 2006

NVLAP Personnel Dosimetry Performance Testing Report for Landauer, Inc., dated January

27, 2006

Section 4OA1: Performance Indicator (PI) VerificationProceduresEP-AD-022, " Nuclear Emergency Planning Performance Indicators," Rev. 2Other DocumentsERO Drill Participation

PI data, 1Q06, 2Q06, 3Q06 & 4Q06Public Notification System PI data, 1Q06, 2Q06, 3Q06 & 4Q06

DEP PI data, 1Q06, 2Q06, 3Q06 & 4Q06

Section 4OA5: Other ActivitiesOther DocumentsReport

MPR 0108-0301-18, Revision 1, December 8, 2005Report MPR -2613, Revision 2, May 2006

Report

MPR-2634, Revision 1, May 2006

Structural Examination of Spent Fuel Pool Structures, May 12, 2006

Quarterly Remedial Action Report, Fourth Quarter 2006, March 2007

In-situ Test Plan -Salem FHB Structural Assessment, March 14, 2007

Response to Unresolved Item, dated

March 30, 2007

2Attachment

LIST OF ACRONYMS

ABVAuxiliary Building VentilationACMAdverse Condition Monitoring & Contingency Plan

AFWA uxiliary Feedwater

ALARAA Low As is Reasonably Achievable

ANSAlert and Notification System

CCComponent Cooling

CEDECommitted Effective Dose Equivalent

CFCUContainment Fan Coil Unit

CFRC ode of Federal Regulations

CO 2Carbon Dioxide

DEPDrill and Exercise Performance

EALEmergency Action Level

ECACEmergency Control Air Compressor

EOFE mergency Operations Facility

EP Emergency Preparedness

EROEmergency Response Organization

FOTPsFuel Oil Transfer Pumps

HELBHigh Energy Line Break

IMCInspection Manual Chapter

MRMaintenance Rule

NCVNon-cited Violation

NOTFNotification

NRCNuclear Regulatory Commission

NVLAPNational Voluntary Laboratory Accreditation Program

OAOther Activities

OpESSOperating Experience Smart Sample

PARSPublicly Available Records

PIPerformance Indicator

PORVPilot Operated Relief Valve

PSEGP ublic Service Enterprise Group Nuclear

LLC [[]]

PSFFPreventable System Functional Failure

RCPR eactor Coolant Pump

RCS Reactor Coolant System

RHRResidual Heat Removal

RWPRadiation Work Permit

S1R18Salem Generating Station Unit 1 Eighteenth Refueling Outage

SACService Air Compressor

SBOStation Blackout

SDPSignificance Determination Process

SFPSpent Fuel Pool

SGSSalem Generating Station

SPTStation Power Transformer

SRASenior Reactor Analyst

SWService Water

SWPService Water Pump

SWSService Water Strainer

A-13Attachment TDAFWTurbine Driven Auxiliary Feedwater UFSARUpdated Final Safety Analysis Report

URIUnresolved Item

VHRAVery High Radiation Area

VTDVendor Technical Document

WCDWork Clearance Document

WOW ork Order

v t e Inspection Report - Salem - 2007002
80 \| 81 \| 82 \| 83 \| 84 \| 85 \| 86 \| 87 \| 88 \| 89 \| 90 \| 91 \| 92 \| 93 \| 94 \| 95 \| 96 \| 97 \| 98 \| 99 00 \| 01 \| 02 \| 03 \| 04 \| 05 \| 06 \| 07 \| 08 \| 09 \| 10 \| 11 \| 12 \| 13 \| 14 \| 15 \| 16 \| 17 \| 18 \| 19 \| 20 \| 21 \| 22 \| 23 \| 24 \| 25 \|
2007 Quarterly Integrated 1Q (0) 2Q (1) 3Q (0) 4Q (0) Assessments Mid Cycle End of Cycle Security 402(0) 403(0) 406(0) Operator Exams Emergency Planning Other