IR 05000272/2006007

IR 05000272-06-007, 05000311-06-007 on 03/13 - 31/2006, Salem Nuclear Generating Station, Units 1 and 2; Triennial Fire Protection Team Inspection, Fire Protection

ML061430170
Person / Time
Site:	Salem
Issue date:	05/23/2006
From:	Rogge J Engineering Region 1 Branch 3
To:	Levis W Public Service Enterprise Group
References
IR-06-007
Download: ML061430170 (30)

Text

May 23, 2006Mr. William Levis Senior Vice President and Chief Nuclear Officer PSEG LLC - N09

P. O. Box 236 Hancocks Bridge, NJ 08038SUBJECT:SALEM NUCLEAR GENERATING STATION - NRC TRIENNIAL FIREPROTECTION INSPECTION REPORT 05000272/2006007, 05000311/2006007

Dear Mr. Levis:

On March 31, 2006, the NRC completed a triennial fire protection team inspection at yourSalem Nuclear Generating Station. The enclosed report documents the inspection resultswhich were discussed at an initial meeting on March 31, 2006, and a telephone conference call exit meeting to update the initial findings on April 10, 2006, with Mr. T. Joyce and other members of your staff.The inspection examined activities conducted under your license as they relate to safety andcompliance with the Commission's rules and regulations and with the conditions of your license.

The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.Based on the results of this inspection, the NRC identified one finding of very low safetysignificance (Green) that was a violation of NRC requirements. However, because of the verylow 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.1 of the NRC Enforcement Policy. Additionally, a licensee-identified violation which was determined to be of very low significance is documented in this report. If you contest the NCV in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory Commission, 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.

Mr. William Levis2In 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 theNRC Public Document Room or from the Publicly Available Records (PARS) com ponent 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/John F. Rogge, ChiefEngineering Branch 3 Division of Reactor SafetyDocket Nos. 50-272, 50-311License Nos. DPR-70, DPR-75

Enclosure:

NRC Inspection Report 05000272/2006007, 05000311/2006007

REGION IDocket Nos.50-272, 50-311 License Nos.DPR-70, DPR-75 Report No.05000272/2006007, 05000311/2006007 Licensee:Public Service Enterprise Group Nuclear LLC Facility:Salem Nuclear Generating Station, Units 1 and 2Location:P. O. Box 236Hancocks Bridge, NJ 08038Dates:March 13 - 31, 2006 Inspectors:L. Cheung, Senior Reactor Inspector, DRSP. Finney, Reactor Inspector, DRS M. Patel, Reactor Inspector, DRS T. Sicola, Reactor Inspector, DRSApproved by:John F. Rogge, ChiefEngineering Branch 3 Division of Reactor Safety Enclosure ii

SUMMARY OF FINDINGS

IR 05000272/2006007, 05000311/2006007 on 03/13 - 31/ 2006, Salem Nuclear GeneratingStation, Units 1 and 2; Triennial Fire Protection Team Inspection, Fire Protection.This report covered a two-week triennial fire protection team inspection by four Region Ispecialist inspectors. One Green NCV was identified. The significance of most findings is indicated by their color (Green, White, Yellow, 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'sprogram for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, "Reactor Oversight Process," Revision 3, dated July 2000.A.

Cornerstone: Mitigating Systems

Green.

The team identified a non-cited violation (NCV) for failure to maintainequipment required for cold shutdown (CSD) repairs in the designated location. Specifically, procedure SC.MD-AB.ZZ-0001, Installation of Temporary 4KVPower Cables to CCW and RHR Motors, states that "All equipment required toinstall jumpers, cooling fans and make cable terminations are located in the Salem Safe Shutdown Equipment Storage Area." Salem Safe Shutdown Equipment Storage Area is located in the Northwest area of the Hope Creek Unit reactor building. An inventory of the designated area in response to inspector inquiries revealed that a significant number of CSD repair materials was found missing. The licensee generated a notification and restocked the missing repair materials.The finding is more than minor because it is associated with the MitigatingSystems cornerstones attribute objective to ensure the availability of the post-firecold shutdown system that responds to initiating events to prevent undesirableconsequences. Under Manual Chapter 0609 Appendix F, Fire Protection, the finding was evaluated as representing a medium degradation. However, because the equipment involved only effects Cold Shutdown, the finding was determined to be of very low safety significance in accordance with the Fire Protection Significance Determination Process. The performance deficiency had a problem identification and resolution cross-cutting aspect because there was a previous case where cold shutdown repair equipment were found missing and where the corrective actions were ineffective to prevent recurrence. (Section 1R10)

B.Licensee-Identified Violations

A violation of very low safety significance, which was identified by the licensee has beenreviewed by the inspectors. Corrective actions taken or planned by the licensee have been entered into the licensee's corrective action program. This violation and its associated corrective action tracking number are listed in Section 4OA7 of this report.

Enclosure

REPORT DETAILS

BackgroundThis report presents the results of a triennial fire protection inspection conducted in accordancewith NRC Inspection Procedure (IP) 71111.05T, "Fire Protection." The objective of theinspection was to assess whether PSEG, LLC, has implemented an adequate fire protection program and that post-fire safe shutdown capabilities have been established and are beingproperly maintained at the Salem Nuclear Generating Station, Units 1 and 2. Five plant areasthat included the following fire areas (FAs), were selected for detailed review based on risk insights from the Salem Individual Plant Examination of External Events (IPEEE): Fire Area 12FA-AB-122A, Fire Area 1FA-AB-84B, Fire Area 1FA-EP-100G, Fire Area 2FA-AB-84B, Fire Area 2FA-EP-100G. The inspection team evaluated PSEG's fire protection program (FPP) against applicablerequirements which include plant Technical Specifications, Operating License Conditions 2.C.5(Unit 1) and 2.C.10 (Unit 2), NRC Safety Evaluations, 10 CFR 50.48 and 10 CFR 50 AppendixR. The team also reviewed related documents that include the Updated Final Safety AnalysisReport (UFSAR), Section 9.5.1, the Salem Fire Hazards Analysis (FHA) and Post-Fire Safe Shutdown Analysis (SSA).Specific documents reviewed by the team are listed in the attachment.2.REACTOR SAFETYCornerstones: Initiating Events, Mitigating Systems1R05Fire Protection

.01 Post-Fire Safe Shutdown From Outside Main Control Room (Alternative Shutdown) andNormal Shutdown

a. Inspection Scope

MethodologyThe team reviewed the safe shutdown analysis, operating procedures, piping andinstrumentation drawings (P&IDs), electrical drawings, the UFSAR and other supporting documents to verify that hot and cold shutdown could be achieved and maintained from outside the control room for fires that rely on shutdown from outside the control room. This review included verification that shutdown from outside the control room could be performed both with and without the availability of offsite power. Plant walkdowns were 2Enclosurealso performed to verify that the plant configuration was consistent with that described inthe FHAR. These inspection activities focused on ensuring the adequacy of systemsselected for reactivity control, reactor coolant makeup, reactor decay heat removal, process monitoring instrumentation and support systems functions. The team verified that the systems and components credited for use during this shutdown method wouldremain free from fire damage. The team verified that the transfer of control from the control room to the alternative shutdown location(s) would not be affected by fire-induced circuit faults (e.g., by the provision of separate fuses and power supplies for alternative shutdown control circuits).Similarly, for fire areas that utilize shutdown from the control room, the team alsoverified that the shutdown methodology properly identified the com ponents and systemsnecessary to achieve and maintain safe shutdown conditions. Operational ImplementationThe team verified that the training program for licensed and non-licensed operatorsincluded alternative shutdown capability. The team also verified that personnel requiredfor safe shutdown using the normal or alternative shutdown systems and procedures aretrained and available onsite at all times, exclusive of those assigned as fire brigade members.The team reviewed the adequacy of procedures utilized for post-fire shutdown andperformed an independent walk through of procedure steps to ensure the implementation and human factors adequacy of the procedures. The team also verified that the operators could be reasonably expected to perform specific actions within the time required to maintain plant parameters within specified limits. Time critical actions which were verified included restoration of AC electrical power, establishing the remote shutdown panel, and establishing decay heat removal.Specific procedures reviewed for alternative shutdown, including shutdown from outsidethe control room included the following:S1.OP-AB.CR-0002(Q), Control Room Evacuation Due To Fire In The ControlRoom, Relay Room, 460/230V Switchgear Room, or 4KV Switchgear Room;S2.OP-AB.CR-0002(Q), Control Room Evacuation Due To Fire In The ControlRoom, Relay Room, 460/230V Switchgear Room, or 4KV Switchgear Room;S1.OP-AB.FIRE-0001(Q), Control Room Fire Response;S2.OP-AB.FIRE-0001(Q), Control Room Fire Response;S1.OP-AB.FIRE-0002(Q), Fire Damage Mitigation;S2.OP-AB.FIRE-0002(Q), Fire Damage Mitigation;SC.MD-AB.ZZ-0001(Q), Installation Of Temporary 4KV Power Cables to CCW and RHR Motors.The team reviewed manual actions to ensure that they had been properly reviewed andapproved and that the actions could be implemented in accordance with plant procedures in the time necessary to support the safe shutdown method for each fire 3Enclosurearea. The team also reviewed the periodic testing of the alternative shutdown transfercapability and instrumentation and control functions to ensure the tests are adequate toensure the functionality of the alternative shutdown capability.

b. Findings

Introduction.

The team identified an unresolved item concerning the ability of operators to perform the activities specified in alternate safe shutdown procedure S1.OP-AB.CR-0002(Q) Revision 18, and S2.OP-AB.CR-0002(Q) Revision 21, "Control Room Evacuation Due To Fire In The Control Room, Relay Room, 460/230V Switchgear Room, or 4KV Switchgear Room." Specifically, the procedure requires operators to enter the Turbine-Driven Auxiliary Feed Pump (TDAFP) Enclosure and the Outer PipingPenetration Area (OPPA) to perform manual actions during post-fire alternate shutdown (ASD). Environmental conditions due to losses of air-conditioning and steam flow through piping in these areas may cause temperatures to rise such that personnel would not be able to either enter or stay in the area to perform requir ed tasks. This issue willremain unresolved pending further NRC review of temperature modeling of the areasunder consideration and analysis of the results.Description. Following review and walkdown of Attachments 4,5,7 and 9 of S2.OP-AB.CR-0002(Q) Revision 21, the team noted the following:1) Attachment 7, actions for the #2 Nuclear Equipment Operator (NEO) require theoperator to enter the Outer Piping Penetration Area (OPPA) to manually close two main steam power operated relief valves (22/24 MS10) and two Main Steam Isolation Valve (MSIV) bypass valves (22/24 MS 18). The Operator then stays in the area, maintaining communications with the Control Room Supervisor via sound-powered phones. 2) Attachment 5, actions for the Plant Operator (PO) require the operator to enterthe Turbine-Driven Auxiliary Feed Pump (TDAFP) Enclosure to manually controlthe Steam Generator Auxiliary Feedwater Inlet Valves. The procedure thenrequires the operator to "Adjust AF11 valves to maintain all Steam Generator levels between 15% and 33% narrow range..." which may require the operator to enter the enclosure as necessary to maintain these levels.After performing the walkdowns of the areas, the team questioned whether habitabilityconcerns were accounted for during the development of the procedures, or if any studies were performed to determine temperature levels in the areas of concern during alternate shutdown conditions. The team was provided with Calculation S-C-AUX-MDC00737, Loss of Ventilation During Station Blackout, Revision 2, which indicated thatduring certain conditions, temperature in the TDAFP enclosure could reach temperatures between 177 F and 256 F. Additionally, the report indicated that theOPPA temperature could reach 211.5 F. The licensee stated that the calculationswere performed for a Station Blackout (SBO) condition, but conceded that enoughsimilarities between the SBO and ASD scenarios existed to warrant further evaluation.

4EnclosureThe team's review of Calculation S-C-ABV-MEE-1472, Revision 0, Effect of the Loss ofAuxiliary Building Ventilation on Appendix R Safe Shutdown Electrical Equipment andthe Heat Stress Effect on the Capability to Perform Manual Actions, indicated that thetemperature in the TDAFP enclosure could reach 149 degrees with the door closed.

This document continues to state "no manual actions are required to be performed inside of this room." The team's walkdown of Attachment 5 to Procedure S2.OP-AB.CR-0002(Q), Revision 21, indicates this to be an incorrect assumption.While the licensee has procedures to evaluate stay times for heat stress concerns asdescribed in NC.IS-TM.ZZ-0001(Z), Revision 8, Nuclear Department Safety Manual, it appears that the ASD procedures were not evaluated for heat stress concerns during operator manual actions. The team concluded that the identified issue concerning potential effects of temperatureon personnel ability to perform alternate safe shutdown is an unresolved item pendingfurther NRC review of licensee's corrective actions. (URI 05000272/2006007-01,05000311/2006007-01, Temperature Habitability Effects on the Ability to PerformAlternate Shut Down Manual Actions)

.02 Protection of Safe Shutdown Capabilities

a. Inspection Scope

The team reviewed the fire hazards analysis, safe shutdown analyses and supportingdrawings and documentation to verify that safe shutdown capabilities were properlyprotected. The team ensured that separation requirements of Section III.G of 10 CFR50, Appendix R were maintained for the credited safe shutdown equipment and theirsupporting power, control and instrumentation cables. This review included an assessment of the adequacy of the selected systems for reactivity control, reactorcoolant makeup, reactor heat removal, process monitoring, and associated support system functions. The team reviewed PSEG's procedures and programs for the control of ignition sourcesand transient combustibles to assess their effectiveness in preventing fires and in controlling combustible loading within limits established in the Fire Hazard Analysis (FHA). A sample of hot work and transient combustible control permits were also reviewed. The team performed plant walkdowns to verify that protective features were being properly maintained and administrative controls were being implemented.The team also reviewed PSEG's design control procedures to ensure that the processincluded appropriate reviews and controls to assess plant changes for any potential adverse impact on the fire protection program and/or post-fire safe shutdown analysis and procedures.

b. Findings

Introduction.

The team identified an unresolved item concerning the adequacy ofEvaluation S-CAV-C-MDC-1583, Revision 4, Salem Generating Station - CompensatoryActions for Appendix R & IEEE Loss of Ventilation Scenarios. Specifically, the evaluation considers compensatory actions taken for a loss of air conditioning to the Control Area Relay Room (CARR) and subsequent heat up. This issue remains unresolved pending further NRC review of licensee's calculations of the temperatureprofile in the area under consideration, and the analysis of the results.Description. Following review of Procedures S2.OP-SO.CAV-0001(Q), Revision 34, andS1.OP-SO.CAV-0001(Q), Revision 31, Control Room Area Ventilation Operation, Procedure S1.OP-AB.CAV-0001(Q), Revision 1, Loss of Unit 1 Control Area HVAC, and a walkdown of the Units 1 and 2 CARR areas, the team questioned if the actions taken for a loss of area HVAC (heating, ventilating, and air conditioning) would allow enough cooling to maintain the temperature-sensitive safety equipment at or below levels which would cause the equipment to be inoperable.The two CARRs are separated by a common corridor. ProcedureS1.OP-AB.CAV-0001(Q), Revision 1, calls for fire doors 102-1 (a single door between Unit 1 CARR and the corridor) and 102-2 (between Unit 2 CARR and the corridor) to be opened within 10 minutes of loss of HVAC, and fire doors 107-1 (a double door between Unit 1 CARR and the corridor) and 107-2 (between Unit 2 CARR and the corridor) to be opened at the 2-hour point. Opening of these doors would allow the cool air from the CARR of the unaffected Unit to cool, through the corridor, the components in the CARR of the affected Unit. Evaluation S-C-CAV-MDC-1583, Revision 4, uses a computer based temperature modelto determine the temperature profiles in the affected CARR following the loss of HVAC scenarios. The evaluation calculates an average or 'bulk temperature' for the room without considering the following:1) Important electrical equipment required for safe shutdown and their operabletemperature ranges,2) Ventilation flow paths and cooling-air movement mechanisms in the CARR, 3) Locations of these safe shutdown equipment with regards to ventilation flows, 4) Flow restrictions (due to various electrical cabinets) throughout the CARR, 5) Localized temperatures in the areas where the important safe shutdownequipment are mounted.After discussing the concerns with licens ee system engineers, it was determined thatthe evaluation needed to be revised to address the team's concerns. The licensee has agreed to revise the analysis to more accurately model the conditions in the CARRs during this scenario and reassess the procedures based on the new computer model.

6EnclosureTo ensure that the localized temperature does not exceed the operable temperaturerange of the safe shutdown equipment, the team concluded that the identified issue isan unresolved item (URI) pending further NRC review of licensee's revised calculation.

(URI 05000272/2006007-02, 05000311/2006007-02, Localized Temperatures in theCARR Not to Exceed Safe Shutdown Equipment Operable Temperature During a Loss of HVAC Event).03Passive Fire Protection

a. Inspection Scope

The team walked down accessible portions of the selected fire areas to observe materialcondition and the adequacy of design of fire area boundaries (including walls, fire doors and fire dampers) to ensure they were appropriate for the fire hazards in the area.

The team reviewed installation/repair and qualification records for a sample of penetration seals to ensure the fill material was of the appropriate fire rating and that theinstallation met the engineering design.

b. Findings

No findings of significance were identified..04Active Fire Protection

a. Inspection Scope

The team reviewed the design, maintenance, testing and operation of the fire detectionand suppression systems in the selected plant fire areas. This included verification that the manual and automatic detection and suppression systems were installed, tested andmaintained in accordance with the National Fire Protection Association (NFPA) code of record, or as NRC approved deviations, and that they would control and/or extinguishfires associated with the hazards in the selected areas. A review of the design capabilityof suppression agent delivery systems was verified to meet the code requirements forthe fire hazards involved. The team also performed a walkdown of accessible portions of the detection and suppressions systems in the selected areas as well as a walkdownof major system support equipment in other areas (e.g., fire protection pumps, CarbonDioxide (CO 2) storage tanks and supply system) and assess the material condition ofthe systems and components.The team reviewed electric and diesel fire pump flow and pressure tests to ensure thatthe pumps were meeting their design requirements. The team also reviewed the firemain loop flow tests to ensure that the flow distribution circuits were able to meet the design requirements.

7EnclosureThe team also assessed the fire brigade capabilities by reviewing training andqualification records, and drill critique records. The team also reviewed pre-fire plansand smoke removal plans for the selected fire areas to determine if appropriate information was provided to fire brigade members and plant operators to identify safe shutdown equipment and instrumentation, and to facilitate suppression of a fire thatcould impact post-fire safe shutdown. In addition, the team inspected the fire brigade'sprotective ensembles, self-contained breathing apparatus (SCBA), and various fire brigade equipment (including smoke removal equipment) to determine operational readiness for fire fighting.

b. Findings

No findings of significance were identified.

.05 Protection From Damage From Fire Suppression Activities

a. Inspection Scope

The team performed document reviews and plant walkdowns to verify that redundanttrains of systems required for hot shutdown are not subject to damage from firesuppression activities or from the rupture or inadvertent operation of fire suppression systems. Specifically, the team verified that:A fire in one of the selected fire areas would not directly, through production ofsmoke, heat or hot gases, cause activation of suppression systems that couldpotentially damage all redundant trains.A fire in one of the selected fire areas (or the inadvertent actuation or rupture ofa fire suppression system) would not directly cause damage to all redundanttrains (e.g., sprinkler caused flooding of other than the locally affected train).Adequate drainage is provided in areas protected by water suppression systems.

b. Findings

No findings of significance were identified..06Alternative Shutdown Capability

a. Inspection Scope

Alternative shutdown capability for the areas selected for inspection utilizes shutdownfrom outside the control room and is discussed in Section 1R05.01 of this report.

8Enclosure.07Circuit Analyses

a. Inspection Scope

The team verified that the licensee performed a post-fire safe shutdown analysis for theselected fire areas and that the analysis appropriately identified the structures, systemsand components important to achieving and maintaining post-fire safe shutdown.

Additionally, the team verified that PSEG's analysis ensured that necessary electricalcircuits were properly protected and that circuits that could adversely impact safe shutdown due to hot shorts, shorts to ground or other failures were identified, evaluated and dispositioned to ensure spurious actuations would not prevent safe shutdown.The team's review considered fire and cable attributes, potential undesirableconsequences and common power supply/bus concerns. Specific items included the credibility of the fire threat, cable insulation attributes, cable failure modes, spuriousactuations, actuations resulting in flow diversion or loss of coolant events.

The team also reviewed wiring diagrams and routing lists for a sample of components required for post-fire safe shutdown to verify that cables were routed as described in the cable routing matrices.Cable failure modes were reviewed for the following components:

Emergency Diesel Generators 1B and 2B,Pressurizer Power Relief Valves 1PR 6 and 1PR 7Volume Control Tank First Discharge Stop Valve 1CV 40Pressurizer Level Instruments 1LT 460 B,Pressurizer Pressure Instruments 1PT 1648,Steam Generator Level Instruments (narrow range) 1LT 1640,Steam Generator Pressure Instruments 1PT 1644.The team reviewed circuit breaker coordination studies to ensure equipment needed toconduct post-fire safe shutdown activities would not be impacted due to a lack of coordination. The team confirmed that coordination studies had addressed multiplefaults due to fire. Additionally, the team reviewed a sample of circuit breaker maintenance and records to verify that circuit breakers for components required for post-fire safe shutdown were properly maintained in accordance with procedural requirements.

b. Findings

No findings of significance were identified.

9Enclosure.08Communications

a. Inspection Scope

The team reviewed safe shutdown procedures, the post-fire safe shutdown analysis andassociated documents to verify an adequate method of communications would be available to plant operators following a fire. During this review, the team considered the effects of ambient noise levels, clarity of reception, reliability and coverage patterns. The team also inspected the designated emergency storage lockers to verify the availability of portable radios for the fire brigade. The team verified that communicationsequipment such as repeaters, transmitters, etc. would not be affected by a fire.

b. Findings

No findings of significance were identified..09Emergency Lighting

a. Inspection Scope

The team observed the placement and coverage area of eight-hour emergency lights,and in specified locations permanent essential lighting, throughout the selected fire areas to evaluate their adequacy for illuminating access and egress pathways and anyequipment requiring local operation and/or instrumentation monitoring for post-fire safe shutdown. The team also verified that the battery power supplies were rated for at leastan 8-hour capacity. Preventive maintenance procedures and various documents, including the completed surveillance tests were reviewed to ensure adequate surveillance testing and periodic battery replacements were in place to ensure reliable operation of the eight-hour emergency lights and that the emergency lighting units werebeing maintained consistent with the manufacturer's recommendations and accepted industry practices.

b. Findings

No findings of significance were identified..10Cold Shutdown Repairs

a. Inspection Scope

The team verified that PSEG had dedicated repair procedures, equipment, andmaterials to accomplish repairs of components required for cold shutdown, within the time frames specified in their design and licensing bases. The team verified that the repair equipment, components, tools and materials (e.g., precut cables with prepared attachment lugs) were available and accessible onsite.

b. Findings

Introduction.

The team identified a Green NCV regarding the maintaining of repaircomponents necessary to achieve Cold Shutdown in a specified location as required by the station procedure for installing temporary power cables to the component coolingwater (CCW) and residual heat removal (RHR) pump motors.Description. While conducting an inspection of the alternate and safe shutdownprocedures, the team requested an inventory the Salem Safe Shutdown EquipmentStorage Area described in procedure SC.MD-AB.ZZ-0001 (Q) Installation of Temporary 4KV Power Cables to CCW and RHR Motors. In response to this request, the licenseeconducted a preliminary inspection of the storage area and concluded that substantialrepair equipment was missing. A notification was prepared, and the inventory list fromProcedure SC.MD-AB.ZZ-0001 (Q) was compared to the library copy of the inventory to verify accuracy. While there were some minor discrepancies between the administrative equipment lists, in either case a significant portion of the required equipment was missing. The licensee generated a notification and restocked the missing repair materials.Per Salem USFAR, Salem is committed to 10 CFR 50 Appendix R section III.G.1b whichstates: "Systems necessary to achieve and maintain cold shutdown from either the control room or emergency control station(s) can be repaired within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />." To meet this requirement, the licensee developed a procedure (SC.MD-AB.ZZ-0001 (Q)) to provide power to the Unit 1 or 2 Residual Heat Removal (RHR) pumps and/or theComponent Cooling Water (CCW) pumps via electrical jumpers from the other Unit should a fire in the 4kV power supplies disable this equipment. The procedure specifies that "All equipment required to install jumpers, cooling fans and make cable terminations are located in the Salem Safe Shutdown Equipment Storage Area. Salem SafeShutdown Equipment Storage Area is located in the Northwest area of Hope Creek Unit 2 reactor building 102' elevation." Contrary to this procedure, on March 30, 2006, not allequipment required to install jumpers was found in this specified area. As described in notification 20277307, the following equipment was missing:SC.MD-AB.ZZ-0001 Inventory- 3/C-2/0 AWG cable in 85', 125' and 170' lengths (1 each required, all present but improperly labeled.)

- Cable Reel Strands (none found)

- Raychem Kits (9 required, 5 found)

- Electrical insulating tape (none found)

- Electrical rubber tape (none found)

- A50H119 electrical putty (none found)

- D50H109 contact compound (none found)

- Storage bags and tags (none found)

- Socket Wrench (none found)

- Safety Flags (none found)11Enclosure- Cords for cooling fans (none found)- Heat gun (none found)Library Inventory

- 1/4" Silicone Bronze flat Washers (18 required, 18 missing)- Wire Markers #1 black on White Backgroung (50 required, 50 missing)

- Wire Markers #2 black on White Backgroung (50 required, 50 missing)

- Wire Markers #3 black on White Backgroung (50 required, 50 missing)

- Vinyl insulated ring terminal lugs 1/4 bolt, 10-12 gauge wire (50 required, 50 missing)

- Raychem high Voltage Termination Kits (18 required, 18 missing)

- Raychem heat Shrink Tubes 6" long x

.25 I.D. (50 required, 50 missing)

- #14 Cable ties (500 required, 300 missing)

- 1/2" ASTM 562 nuts (20 required, 20 found, but of ASTM 563 vice the required

562) - 3/8 -16 ASTM 563 nuts (20 required, none found)- 3/8 - 16 x 1" ASTM 307 Hex Head bolts (20 required, 20 missing)

- 3/C-2/0 Triplex cable in 85', 125' and 200' lengths (1 each required, all present but improperly labeled.)The team conducted a walkdown of the designated storage area, and noted that thearea was locked, and a sign was posted designating the equipment in the area wasexclusively for use during Salem Appendix R emergencies. The team also reviewed the results of one previous surveillance and two notifications (20158400 dated September11, 2003, and 20228300 dated March 6, 2005) and noted that cold shutdown repairmaterials were missing in both of the previous inventories. Although the licensee subsequently restocked all missing items, they failed to take an effective corrective action to prevent a repeated recurrence (three consecutive deficient conditions).Analysis. The ability to perform repairs to equipment required to achieve and maintaincold shutdown is vital to ensuring that the safety risks due to fire in a nuclear facility arenot exacerbated by the inability to achieve a stable condition following the extinguishingof the fire.The finding described above is more than minor because it is associated with theMitigating Systems cornerstone attribute of configuration control in that a substantialportion of the equipment required to be available to repair mitigating systems was not inits designated location. While all equipment was eventually found on site, the significant amount of time (60 hours6.944444e-4 days <br />0.0167 hours <br />9.920635e-5 weeks <br />2.283e-5 months <br />) required to locate the equipment exceeded the administrative control limit of 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br /> as delineated in SH.OP-AP.ZZ-0108(Q) Post-Fire Safe Shutdown Equipment - Administrative Controls, Attachment 11, Section 1.4 which states: "The Electrical system Cross-Connect capability should be AVAILABLE foralignment from the associated Unit to the opposite Unit within a 30-hour time period of afire event-" Furthermore, the fact that the storage area is kept locked and specifically 12Enclosureposted as for use under specific circumstances indicates inadequate administrativepolicies and/or procedural adherence. The finding was determined to be of very low safety significance (Green, as describedbelow) because the likelihood of a scenario where a fire damages the equipment serviced by the repair equipment in the discussed storage area, is very low. Manual Chapter 0609 Appendix F, the Fire Protection Significance Determination Process (SDP), states if a finding only affects the ability to reach and maintain a cold-shutdowncondition, the finding screens to Green with no further analysis required.This finding is a performance deficiency and has a problem identification and resolutioncross-cutting aspect because the licensee failed to take an effective corrective action to prevent recurrence after they identified cold shutdown repair materials were missing in March 2005.Enforcement. License conditions 2.C.5 (for Unit 1) and 2.C.10 (for Unit 2) require thatPSEG Nuclear implement and maintain in effect all provisions of the Fire Protection Program as described in the Updated Final Safety Analysis Report (UFSAR). Section 9.5.1.1.5 of the UFSAR identified that the Quality Assurance (QA) Program for FireProtection assures that the requirements for administrative controls for the fireprotection program for safety related areas must be satisfied. This section of the UFSAR also identified the fire protection procedures to be an element of the QA program. Section 4.0 of Salem fire protection procedure for post-fire cold shutdown repair, SC.MD-AB.ZZ-0001(Q), states, "All equipment required to install jumpers, cooling fans and make cable terminations are located in the Salem Safe Shutdown Equipment Storage Area." Contrary to the above, on March 30, 2006, the NRCidentified that many of the materials required for cold shutdown repair were missing.

The licensee issued a notification 20277307 and entered this deficiency into their corrective action program. This violation is being treated as a Non-Cited Violation(NCV), consistent with Section VI.A.1 of the NRC Enforcement Policy. (NCV05000272/2006007-03, 05000311/2006007-03, Failure to Comply with Station Cold Shutdown Repair Procedures)

.11 Compensatory Measures

a. Inspection Scope

The team verified that compensatory measures were in place for out-of-service,degraded or inoperable fire protection and post-fire safe shutdown equipment, systems,or features (e.g., detection and suppression systems and equipment, passive firebarriers, pumps, valves or electrical devices providing safe shutdown functions or capabilities). The team also verified that the short term compensatory measurescompensated for the degraded function or feature until appropriate corrective action could be taken and that PSEG was effective in returning the equipment to service in a reasonable period of time.

b. Findings

No findings of significance were identified.4.OTHER ACTIVITIES 4OA2Identification and Resolution of Problems

.01 Corrective Actions for Fire Protection Deficiencies

a. Inspection Scope

The team verified that the licensee was identifying fire protection and post-fire safeshutdown issues at an appropriate threshold and entering them into the corrective action program. The team also reviewed a sample of selected issues to verify that the licensee had taken or planned appropriate corrective actions.

b. Findings

No findings of significance were identified.4OA5Other Activities.1(Closed) URI 05000272,05000311/200500311 CO 2 Migration on Remote ShutdownOperations.

In January 2005, PSEG determined through preliminary results of an engineeringassessment that upon discharge of carbon dioxide (CO 2) in some areas of the plant dueto fire, hazardous levels of CO 2 concentration could exist in areas required to beaccessible during safe shutdown events. On April 25, 2005, the licensee reported though revision 1 to the Licensee Event Report (LER) 2005-001 that the cause of the carbon dioxide system migration was due to insufficient system design. This issueremained unresolved pending further analysis of the condition and followup inspection to assess the significance of the condition and the adequacy of licensee's associated corrective actions.In June 2005, PSEG completed the root cause evaluation on the timeliness of correctiveactions for the CO 2 migration issue documented in notification 20223951. The teamreviewed PSEG's root cause evaluation and noted that the evaluation had determinedPSEG's failure to identify and to rectify the CO 2 migration issue in a timely manner wasa condition adverse to quality. During this inspection, the team reviewed and discussed the engineering assessmentresults with the licensee. The results from Framatone engineering assessment concluded that in the event of a CO system actuation due to a fire in the 4160 volt or460 volt Switchgear Rooms, or Lower Electrical Penetration Areas, CO 2 migration would 14Enclosureresult in some of the adjacent areas having concentration levels that would require theuse of self-contained breathing apparatus (SCBAs) for entry or would be restricted to transit activities only. On January 26, 2005, PSEG isolated the carbon dioxide suppression systems for Salem Units 1 and 2, and placed appropriate compensatorymeasures in accordance with the Salem Fire Protection Program. The team evaluated PSEG's long-term resolution strategy, which included eliminating CO 2 in these fire areasand converting to either an alternate, non-hazar dous gaseous system or a water basedsuppression system. On March 10, 2006, PSEG's Plant Health Committee (PHC)approved the recommendation to initiate a project to complete conceptual designs, material estimates, and implementation of replacing the existing CO 2 fire suppressionsystem with an interlocked preaction water suppression system. This unresolved item isclosed. See Section

4OA7 of this report for the detailed risk assessment of this licensee

identified finding..2(Closed) URI 05000272,05000311/2003002-01 Fire Induced Spurious Opening of MS10ValvesInspection Report 05000272,311/2003002 documented a potential finding that for threefire areas (inner piping penetration area, outer penetration area, and 1(2)FA-TGA-88in the turbine building), the licensee has not protected a full train of equipment necessaryto achieve and maintain hot shutdown. For each unit, there are four steam generator power operated relief valves (MS10), which discharge the steam to the atmosphere when open. These are 6" air operated valves which fail close when the pilot solenoid valves are de-energized or when the instrument air is lost. The control circuit for each solenoid valve is located in an instrument panel and a fire-induced hot short can cause the solenoid valve to be energized and the associated MS10 valve to open inadvertently.

The pilot solenoid valves for two MS10 valves are located in one fire area, but the panels are separated by 12 feet. The licensee completed an analysis, S-C-MS-MEE-1533, Loss of Main Steam IsolationComponents due to an Appendix R Fire in 1(2)FA-PP-92K or 1(2)FA-PP-1000H to evaluate two concerns: 1) reactivity addition due to excessive cool down rate, and, 2)maintaining heat sink available. The analysis showed that with one MS10 valve inadvertently open, the initial steam flow rate (575,710 lbm/hr for a short duration) is within the analyzed condition (1,100.000 lbm/hr in USFAR Section 15.2.13). If two MS10s open simultaneously (beginning at the same moment), the excess cool down rate will be slightly outside the analyzed condition. The licensee stated that multiplespurious actuations (hot shorts) were outside their licensing basis. The above analysis also showed that maintaining heat sink was acceptable as the other two MS10 valves (in another fire area) were not affected. However, the affected MS10 valves must be closed manually to prevent steam generators from boiling dry. The licenseeincorporated manual actions to close the potentially affected MS10 valves if a fire occurs in the identified fire areas. The licensee also completed another analysis, S-C-FP-FEE-1746, Acceptable Response Times to Appendix R Failures, which showed that (in Table 4), for the spurious opening of a single MS10, the cool down rate for the first hour is

79.2 F, which is also within the allowed cooling rate of 100 F per hour.

15EnclosureSalem's licensing basis only assumes a single fire-induced spurious action, and theinadvertent opening of a single MS 10 valve was determined to be within the analyzed condition. Therefore this unresolved item is closed. 4OA6Meetings, Including ExitExit Meeting SummaryThe team presented their preliminary inspection results to Mr. T. Joyce, Vice President,and other members of the site staff at an initial meeting on March 31, 2006, and a telephone conference call exit meeting to update the initial findings on April 10, 2006.

No proprietary information was included in this inspection report.4OA7Licensee-Identified ViolationThe following violation of very low safety significance (Green) was identified by thelicensee and is a violation of NRC requirements which meet the criteria of Section VI ofthe Enforcement Policy, NUREG-1600, for being dispositioned as NCVs.*.License conditions 2.C.5 (for Unit 1) and 2.C.10 (for Unit 2) require that PSEGNuclear implement and maintain in effect all provisions of the Fire Protection Program as described in the Updated Final Safety Analysis Report (UFSAR).

UFSAR Section 9.5.1.1.5 requires corrective action measures to be established to ensure that conditions adverse to fire protection are promptly identified, reported, and corrected. Contrary to the above, as of January 25, 2005, PSEGfailed to promptly identify, report and correct the CO 2 migration issue, althoughPSEG had received the final calculation from Framatome on December 3, 2003, which showed that the potential CO 2 leakage to the work control area (next tothe control room) could reach an unacceptable level (up to 12.6% CO 2concentration). The CO 2 migration issue is a condition adverse to fire protection. PSEG documented this issue in LER 2005-001 and in Notification 20223951. This finding is more than minor because it had a potential to impact the ability tosafely shutdown Salem Unit 1 and 2 in the event of fire in the 4160 volt and 460 volt Switchgear Rooms. The finding affects the Mitigating Systems Cornerstone and was evaluated using Inspection Manual Chapter (IMC) 0609, Appendix F, and was determined to represent a potential fire protection risk of very low safety significance (green). The Phase 2 risk assessment result by the NRC inspectorswas formulated using conservative assumption. Based upon the limitation of Appendix F in characterizing the risk of fire scenarios impacting the control room and potentially resulting in a control room evacuation, the licensee performed amore detailed Phase 3 risk assessment. The licensee's detailed analysis confirmed the inspectors' Phase 2 result. This analysis was independently reviewed by the Region I Senior Reactor Analyst who agreed with the methodology and resulting characterization.

A-1Attachment

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

PSEG Personnel

J. Balcita, Engineer, Design Engineering

D. Benyak, Director, Regulatory Assurance

W. Buirch, Supt, Fire Protection Operations

M. Ewirtz, DPS Support Manager, Salem Operations

A. Fakhar, Senior Manager, Design Engineering

C. Fricker, Plant Manager, Salem

T. Joyce, Site Vice President, Salem

S. Mannon, Manager Regulatory Assurance

K. Mathur, Engineer, Mechanical Design Engineering

W. Mattinely, Manager, Salem Nuclear Oversight

M. Mog, Shift Supervisor, Salem Operation

T. Moore, director, Project Management

A. Robert III, Manager, Engineering Program

S. Robitzski, Director, Engineering

D. Shumaker, Engineer, Program Engineering

J. Stone, Director, Salem Maintenance

R. Wegner, Director, Salem Work Management

J. Wearne, Engineer, Salem LicensingExelon Corporation

W. Lewis, Manager, Engineering

C. Pragman, Manager, Corporate Fire Protection ProgramNew Jersey Department of Environmental Protection

E. Rosenfeld, Engineer

NRC

D. Orr, Senior Resident Inspector, Salem Units 1 and 2

J. Rogge, Chief, Engineering Branch 3, Division of Reactor Safety

A-2Attachment

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

05000272,

05000311/2006007-01URITemperature Habitability Effects on the Ability toPerform Alternate Shut Down Manual Actions05000272,

05000311/2006007-02URILocalized Temperatures in the CARR Not toExceed Safe Shutdown Equipment Operable

Temperature During a Loss of HVAC EventOpen and

Closed

05000272,

05000311/2006007-03NCV Failure to Comply with Station Cold ShutdownRepair Procedures (Section 1R05)

Closed

05000272,

05000311/2005003-11 URICO2 Migration on Remote Shutdown Operations05000272,

05000311/2003002-01 URIFire Induced Spurious Opening of MS10 Valves

Discussed

None

A-3Attachment

LIST OF DOCUMENTS REVIEWED

Fire Protection Licensing DocumentsAmendment No. 2 to Facility Operating License No.

DPR-70.

NRC letter dated 11/20/79to Mr. P. Librizzi, General ManagerJune 17, 1983, Letter to PSE&G, Salem Nuclear Generating Station, Unit No. 1, FireProtection - Request for Exemption from Requirements of Appendix R to 10 CFR 50,