IR 05000400/2008008: Difference between revisions

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{{#Wiki_filter:UNITED STATES NUCLEAR REGULATORY COMMISSION REGION II SAM NUNN ATLANTA FEDERAL CENTER 61 FORSYTH STREET, SW, SUITE 23T85 ATLANTA, GEORGIA 30303-8931 December 19, 2008 Mr. Christopher Vice President Carolina Power & Light Company Shearon Harris Nuclear Plant P.O. Box 165, Mail Zone 1 New Hill, NC 27562-0165 SUBJECT: SHEARON HARRIS NUCLEAR POWER PLANT - NRC TRIENNIAL FIRE PROTECTION INSPECTION REPORT 05000400/2008008 AND EXERCISE OF ENFORCEMENT DISCRETION
{{#Wiki_filter:UNITED STATES NUCLEAR REGULATORY COMMISSION December 19, 2008
 
==SUBJECT:==
SHEARON HARRIS NUCLEAR POWER PLANT - NRC TRIENNIAL FIRE PROTECTION INSPECTION REPORT 05000400/2008008 AND EXERCISE OF ENFORCEMENT DISCRETION


==Dear Mr. Burton:==
==Dear Mr. Burton:==
On October 10, 2008, the U.S. Nuclear Regulatory Commission (NRC) completed a triennial fire protection inspection at your Shearon Harris Nuclear Plant. The enclosed inspection report documents the inspection results, which were discussed on October 10, 2008, with you and other members of your staff. Following completion of additional review in the Region II office, another exit meeting was held by telephone with you and other members of your staff on December 18, 2008, to provide an update on changes to the preliminary inspection findings.
On October 10, 2008, the U.S. Nuclear Regulatory Commission (NRC) completed a triennial fire protection inspection at your Shearon Harris Nuclear Plant. The enclosed inspection report documents the inspection results, which were discussed on October 10, 2008, with you and other members of your staff. Following completion of additional review in the Region II office, another exit meeting was held by telephone with you and other members of your staff on December 18, 2008, to provide an update on changes to the preliminary inspection findings.


The inspection examined activities conducted under your license as they relate to safety and compliance 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 inspection examined activities conducted under your license as they relate to safety and compliance with the Commissions rules and regulations and with the conditions of your license.
 
The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.


This report documents one NRC-identified finding of very low safety significance (Green) which was determined to involve a violation of NRC requirements. However, because of the very low safety significance and because it was entered into your corrective action program, the NRC is treating this finding as a non-cited violation (NCV) consistent with Section VI.A.1 of the NRC Enforcement Policy. If you contest any NCV in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory Commission, ATTN.: Document Control Desk, Washington, DC 20555-0001; with copies to the Regional Administrator, Region II; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at the Shearon Harris site.
This report documents one NRC-identified finding of very low safety significance (Green) which was determined to involve a violation of NRC requirements. However, because of the very low safety significance and because it was entered into your corrective action program, the NRC is treating this finding as a non-cited violation (NCV) consistent with Section VI.A.1 of the NRC Enforcement Policy. If you contest any NCV in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory Commission, ATTN.: Document Control Desk, Washington, DC 20555-0001; with copies to the Regional Administrator, Region II; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at the Shearon Harris site.


In addition, the enclosed report documents one noncompliance that was identified during the inspection for which the NRC is exercising enforcement discretion. The NRC is not taking any enforcement action for this noncompliance because it meets the criteria of the NRC Enforcement Policy, "Interim Enforcement Policy Regarding Enforcement Discretion for Certain Fire Protection Issues (10 CFR 50.48)," and NRC Inspection Manual Chapter 0305, "Violations in Specified Areas of Interest Qualifying for Enforcement Discretion."
In addition, the enclosed report documents one noncompliance that was identified during the inspection for which the NRC is exercising enforcement discretion. The NRC is not taking any enforcement action for this noncompliance because it meets the criteria of the NRC Enforcement Policy, Interim Enforcement Policy Regarding Enforcement Discretion for Certain Fire Protection Issues (10 CFR 50.48), and NRC Inspection Manual Chapter 0305, Violations in Specified Areas of Interest Qualifying for Enforcement Discretion.


CP&L 2In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records 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).
CP&L   2 In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records 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,
Sincerely,
/RA: Paul fillion for/  
/RA: Paul fillion for/
 
Rebecca L. Nease, Chief, Engineering Branch 2 Division of Reactor Safety Docket No.: 50-400 License No.: NPF-63
Rebecca L. Nease, Chief, Engineering Branch 2 Division of Reactor Safety Docket No.: 50-400 License No.: NPF-63  


===Enclosure:===
===Enclosure:===
Inspection Report 05000400/2008008 w/Attachment: Supplemental Information  
Inspection Report 05000400/2008008 w/Attachment: Supplemental Information


REGION II==
REGION II==
Docket No.: 50-400 License No.: NPF-63  
Docket No.: 50-400 License No.: NPF-63 Report No.: 05000400/2008008 Licensee: Carolina Power and Light Company Facility: Shearon Harris Nuclear Power Plant, Unit 1 Location: New Hill, North Carolina Dates: September 22-26, 2008 (Week 1)
October 6-10, 2008 (Week 2)
Inspectors: M. Thomas, Senior Reactor Inspector (Team Lead)
O. Lopez, Fire Protection Inspector in Training B. Melly, Fire Protection Engineer (Consultant)
N. Merriweather, Senior Reactor Inspector K. Miller, Reactor Inspector in Training N. Staples, Reactor Inspector L. Suggs, Reactor Inspector Approved by: Rebecca L. Nease, Chief Engineering Branch 2 Division of Reactor Safety Enclosure


Report No.: 05000400/2008008 Licensee: Carolina Power and Light Company Facility: Shearon Harris Nuclear Power Plant, Unit 1 Location: New Hill, North Carolina
=SUMMARY OF FINDINGS=
IR 05000400/2008008; 09/22-26/2008 and 10/06-10/2008; Shearon Harris Nuclear Power Plant,


Dates: September 22-26, 2008 (Week 1) October 6-10, 2008 (Week 2)
Unit 1; Triennial Fire Protection Inspection.
Inspectors: M. Thomas, Senior Reactor Inspector (Team Lead) O. Lopez, Fire Protection Inspector in Training B. Melly, Fire Protection Engineer (Consultant) N. Merriweather, Senior Reactor Inspector K. Miller, Reactor Inspector in Training N. Staples, Reactor Inspector L. Suggs, Reactor Inspector Approved by: Rebecca L. Nease, Chief Engineering Branch 2 Division of Reactor Safety Enclosure


=SUMMARY OF FINDINGS=
This report covers an announced two-week triennial fire protection inspection by a team of four regional inspectors and one contract inspector. One Green non-cited violation was identified.
IR 05000400/2008008; 09/22-26/2008 and 10/06-10/2008; Shearon Harris Nuclear Power Plant, Unit 1; Triennial Fire Protection Inspection.


This report covers an announced two-week triennial fire protection inspection by a team of four regional inspectors and one contract inspector. One Green non-cited violation 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'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.
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'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===
===NRC-Identified and Self-Revealing Findings===


===Cornerstone: Mitigating Systems===
===Cornerstone: Mitigating Systems===
* Green: The team identified a non-cited violation of Shearon Harris Unit 1 operating license condition 2.F, for the licensee's failure to install the sprinkler system in Cable Spreading Room A (CSRA) in accordance with the approved fire protection program (FPP). Specifically, the installed system would not have been able to deliver the sprinkler system design density of 0.3 gallons per minute/square foot in CSRA, as stated in the FPP in Updated Final Safety Analysis Report Section 9.5.1.2.3. The licensee entered this issue in the corrective action program and established a continuous fire watch in CSRA as a compensatory measure in accordance with the Shearon Harris FPP.
* Green: The team identified a non-cited violation of Shearon Harris Unit 1 operating license condition 2.F, for the licensees failure to install the sprinkler system in Cable Spreading Room A (CSRA) in accordance with the approved fire protection program (FPP). Specifically, the installed system would not have been able to deliver the sprinkler system design density of 0.3 gallons per minute/square foot in CSRA, as stated in the FPP in Updated Final Safety Analysis Report Section 9.5.1.2.3. The licensee entered this issue in the corrective action program and established a continuous fire watch in CSRA as a compensatory measure in accordance with the Shearon Harris FPP.


The licensee's failure to install the sprinkler system in CSRA in accordance with the approved FPP is a performance deficiency. This finding is more than minor because the installed sprinkler system degraded one of the fire protection defense in depth elements and it affected the reactor safety Mitigating Systems cornerstone objective. The team completed a Phase 2 screening of the finding in accordance with IMC 0609, Appendix F, Attachment 1, Part 2, Fire Protection SDP Phase 2 Worksheet, and concluded that the finding was of very low safety significance (Green), in accordance with Step 2.5, Task 2.5.5 of the Worksheet, because there was a safe shutdown path available which was independent of CSRA. The cause of this finding was not associated with a cross-cutting area because it is not reflective of current licensee performance.  (Section 1R05.04) 
The licensees failure to install the sprinkler system in CSRA in accordance with the approved FPP is a performance deficiency. This finding is more than minor because the installed sprinkler system degraded one of the fire protection defense in depth elements and it affected the reactor safety Mitigating Systems cornerstone objective.


===B. Licensee-Identified Violations===
The team completed a Phase 2 screening of the finding in accordance with IMC 0609, Appendix F, Attachment 1, Part 2, Fire Protection SDP Phase 2 Worksheet, and concluded that the finding was of very low safety significance (Green), in accordance with Step 2.5, Task 2.5.5 of the Worksheet, because there was a safe shutdown path available which was independent of CSRA. The cause of this finding was not associated with a cross-cutting area because it is not reflective of current licensee performance. (Section 1R05.04)
 
===Licensee-Identified Violations===


None.
None.
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==REACTOR SAFETY==
==REACTOR SAFETY==
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity  
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity


{{a|1R05}}
{{a|1R05}}
==1R05 Fire Protection==
==1R05 Fire Protection==


This report presents the results of a triennial fire protection inspection for a plant in transition to National Fire Protection Association (NFPA) Standard 805, "Performance- Based Standard for Fire Protection for Light Water Reactor Electric Generating Plants, 2001 Edition."  This inspection was conducted in accordance with NRC Inspection Procedure (IP) 71111.05TTP, "Fire Protection-NFPA 805 Transition Period (Triennial)."  The objective of the inspection was to review the Shearon Harris Unit 1 FPP for selected risk-significant fire areas (FAs)/fire zones (FZs). The team selected three FAs for detailed review to examine the licensee's implementation of the FPP. The three FAs were selected based on risk insights from the licensee's Individual Plant Examination for External Events, information contained in FPP documents, results of prior NRC triennial fire protection inspections, and in-plant walk downs by the team. Section 71111.05-05 of the IP specifies a minimum sample size of three FAs. Detailed inspection of these three FAs fulfills the procedure completion criteria. The three FAs selected were:
This report presents the results of a triennial fire protection inspection for a plant in transition to National Fire Protection Association (NFPA) Standard 805, Performance-Based Standard for Fire Protection for Light Water Reactor Electric Generating Plants, 2001 Edition. This inspection was conducted in accordance with NRC Inspection Procedure (IP) 71111.05TTP, Fire Protection-NFPA 805 Transition Period (Triennial).
 
The objective of the inspection was to review the Shearon Harris Unit 1 FPP for selected risk-significant fire areas (FAs)/fire zones (FZs). The team selected three FAs for detailed review to examine the licensees implementation of the FPP. The three FAs were selected based on risk insights from the licensees Individual Plant Examination for External Events, information contained in FPP documents, results of prior NRC triennial fire protection inspections, and in-plant walk downs by the team. Section 71111.05-05 of the IP specifies a minimum sample size of three FAs. Detailed inspection of these three FAs fulfills the procedure completion criteria. The three FAs selected were:
* FA 1-A-CSRA, Cable Spread Room A, Reactor Auxiliary Building (RAB), 286 foot (ft.) elevation.
* FA 1-A-CSRA, Cable Spread Room A, Reactor Auxiliary Building (RAB), 286 foot (ft.) elevation.
* FA 1-A-SWGRA, Switchgear Room A, RAB 286 ft. elevation.
* FA 1-A-SWGRA, Switchgear Room A, RAB 286 ft. elevation.
* FA 12-A-CRC1/FZ 12-A-6-PICR1, Control Room Complex, Process Instrument Cabinet Room, RAB 305 ft. elevation.
* FA 12-A-CRC1/FZ 12-A-6-PICR1, Control Room Complex, Process Instrument Cabinet Room, RAB 305 ft. elevation.


The team evaluated the licensee's FPP against applicable requirements, including Operating License Condition 2.F; Title 10 of the Code of Federal Regulations, Part 50.48 (10 CFR 50.48); commitments to NRC Branch Technical Position (BTP) Chemical Engineering Branch (CMEB) 9.5-1, Guidelines for Fire Protection for Nuclear Power Plants; Shearon Harris Updated Final Safety Analysis Report (UFSAR); related NRC safety evaluation reports (SERs) including all applicable supplements; NRC Safety Evaluation dated January 12, 1987; and plant Technical Specifications. The team evaluated each selected FA/FZ against these requirements. The specific documents reviewed by the team are listed in the Attachment to this inspection report.
The team evaluated the licensees FPP against applicable requirements, including Operating License Condition 2.F; Title 10 of the Code of Federal Regulations, Part 50.48 (10 CFR 50.48); commitments to NRC Branch Technical Position (BTP) Chemical Engineering Branch (CMEB) 9.5-1, Guidelines for Fire Protection for Nuclear Power Plants; Shearon Harris Updated Final Safety Analysis Report (UFSAR); related NRC safety evaluation reports (SERs) including all applicable supplements; NRC Safety Evaluation dated January 12, 1987; and plant Technical Specifications. The team evaluated each selected FA/FZ against these requirements. The specific documents reviewed by the team are listed in the Attachment to this inspection report.


===.01 Post-Fire Safe Shutdown From Main Control Room (Normal Shutdown)===
===.01 Post-Fire Safe Shutdown From Main Control Room (Normal Shutdown)===


====a. Inspection Scope====
====a. Inspection Scope====
Methodology The team reviewed the licensee's FPP described in UFSAR Section 9.5.1; NRC SER dated November 1983 (and Supplements 1 through 4); applicable sections of the licensee's post-fire safe shutdown analysis (SSA); plant procedures; simplified flow diagrams; electrical drawings; and other supporting documents. The reviews were performed to verify that hot and cold shutdown could be achieved and maintained from 4the main control room (MCR) for postulated fires in FAs 1-A-CSRA and 1-A-SWGRA. This review also included verification that shutdown from the MCR could be performed both with and without the availability of offsite power. Plant walkdowns were performed to verify that the plant configuration was consistent with that described in the fire hazards analysis and the SSA. The inspection activities focused on ensuring the adequacy of systems selected for reactivity control, reactor coolant makeup, reactor heat removal, process monitoring instrumentation, and support system functions. The team reviewed the systems and components credited for use during this shutdown method to verify that they would remain free from fire damage.
Methodology The team reviewed the licensees FPP described in UFSAR Section 9.5.1; NRC SER dated November 1983 (and Supplements 1 through 4); applicable sections of the licensees post-fire safe shutdown analysis (SSA); plant procedures; simplified flow diagrams; electrical drawings; and other supporting documents. The reviews were performed to verify that hot and cold shutdown could be achieved and maintained from the main control room (MCR) for postulated fires in FAs 1-A-CSRA and 1-A-SWGRA.
 
This review also included verification that shutdown from the MCR could be performed both with and without the availability of offsite power. Plant walkdowns were performed to verify that the plant configuration was consistent with that described in the fire hazards analysis and the SSA. The inspection activities focused on ensuring the adequacy of systems selected for reactivity control, reactor coolant makeup, reactor heat removal, process monitoring instrumentation, and support system functions. The team reviewed the systems and components credited for use during this shutdown method to verify that they would remain free from fire damage.


Operational Implementation The team reviewed the adequacy of procedures utilized for post-fire safe shutdown and performed a walk through of procedure steps to ensure the implementation and human factors adequacy of the procedures. The team also reviewed selected operator actions to verify that the operators could reasonably be expected to perform the specific actions within the time required to maintain plant parameters within specified limits.
Operational Implementation The team reviewed the adequacy of procedures utilized for post-fire safe shutdown and performed a walk through of procedure steps to ensure the implementation and human factors adequacy of the procedures. The team also reviewed selected operator actions to verify that the operators could reasonably be expected to perform the specific actions within the time required to maintain plant parameters within specified limits.


The team reviewed cable routing data for a sample of safe shutdown (SSD) components to determine if the power and/or control circuits for the SSD components could be potentially damaged by a fire in any of the FAs selected. The team reviewed and/or walked down applicable sections of the following abnormal operating procedures (AOPs) for FAs 1-A-CSRA and 1-A-SWGRA.
The team reviewed cable routing data for a sample of safe shutdown (SSD) components to determine if the power and/or control circuits for the SSD components could be potentially damaged by a fire in any of the FAs selected. The team reviewed and/or walked down applicable sections of the following abnormal operating procedures (AOPs)for FAs 1-A-CSRA and 1-A-SWGRA.
* AOP-036.05, Fire Areas: 1-A-CSRA, 1-A-CSRB
* AOP-036.05, Fire Areas: 1-A-CSRA, 1-A-CSRB
* AOP-036.08, Fire Areas: 1-A-SWGRA, 1-A-SWGRB The team reviewed local operator manual actions to ensure that the actions could be implemented in accordance with plant procedures in the times necessary to support the SSD method for the applicable FA and to verify that those actions met the criteria in Enclosure 2 of NRC IP 71111.05TTP. The team reviewed the existing manual action required for hot standby that were specified in the licensee's SSA. The team also reviewed licensee nuclear condition report (NCR) 205333, which was initiated to assess and track resolution of the operator manual action issue as part of the plant-wide risk evaluation during the transition to NFPA 805.
* AOP-036.08, Fire Areas: 1-A-SWGRA, 1-A-SWGRB The team reviewed local operator manual actions to ensure that the actions could be implemented in accordance with plant procedures in the times necessary to support the SSD method for the applicable FA and to verify that those actions met the criteria in 2 of NRC IP 71111.05TTP. The team reviewed the existing manual action required for hot standby that were specified in the licensees SSA. The team also reviewed licensee nuclear condition report (NCR) 205333, which was initiated to assess and track resolution of the operator manual action issue as part of the plant-wide risk evaluation during the transition to NFPA 805.


====b. Findings====
====b. Findings====
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====a. Inspection Scope====
====a. Inspection Scope====
The team reviewed the fire protection features used to protect safe shutdown cables and components to ensure they satisfy the separation and design requirements specified in the BTP CMEB 9.5-1 and implemented by the licensee in UFSAR Section 9.5.1 and the licensee's SSA (Calculation E-5525).
The team reviewed the fire protection features used to protect safe shutdown cables and components to ensure they satisfy the separation and design requirements specified in the BTP CMEB 9.5-1 and implemented by the licensee in UFSAR Section 9.5.1 and the licensees SSA (Calculation E-5525).


The team reviewed those portions of the UFSAR dealing with the safe shutdown. One objective of this review was to evaluate the completeness and depth of the analysis 5which determined the strategy for protecting the various system functions necessary to achieve and maintain hot standby, accomplish long term cool down and achieve cold shutdown following a severe fire.
The team reviewed those portions of the UFSAR dealing with the safe shutdown. One objective of this review was to evaluate the completeness and depth of the analysis which determined the strategy for protecting the various system functions necessary to achieve and maintain hot standby, accomplish long term cool down and achieve cold shutdown following a severe fire.


Through a combination of design information review and in-plant inspection, the team ascertained whether the fire protection features in place to protect SSD capability satisfied the separation and design requirements specified in BTP CMEB 9.5-1 (e.g., a FA with one-hour fire barriers around the SSD cables together with area wide automatic suppression and detection would meet the requirements).
Through a combination of design information review and in-plant inspection, the team ascertained whether the fire protection features in place to protect SSD capability satisfied the separation and design requirements specified in BTP CMEB 9.5-1 (e.g., a FA with one-hour fire barriers around the SSD cables together with area wide automatic suppression and detection would meet the requirements).
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The team reviewed the station penetration seal program and selected seals during plant walkdowns to verify that the penetration seal engineering designs could be traced back to qualified fire tests that support the penetration seals rating.
The team reviewed the station penetration seal program and selected seals during plant walkdowns to verify that the penetration seal engineering designs could be traced back to qualified fire tests that support the penetration seals rating.


The team reviewed the licensee's responses (dated April 28, 2006, and June 9, 2006) to Generic Letter 2006-03, Potentially Nonconforming HEMYC and MT Fire Barrier Configurations, to verify that compensatory measures were in place until resolution of the degraded fire barriers is accomplished during the licensee's transition process to NFPA 805.
The team reviewed the licensees responses (dated April 28, 2006, and June 9, 2006) to Generic Letter 2006-03, Potentially Nonconforming HEMYC and MT Fire Barrier Configurations, to verify that compensatory measures were in place until resolution of the degraded fire barriers is accomplished during the licensees transition process to NFPA 805.


====b. Findings====
====b. Findings====
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====a. Inspection Scope====
====a. Inspection Scope====
The team evaluated the material condition and operational lineup of fire detection and suppression systems through in-plant observation of systems, design document reviews, and reference to the applicable NFPA codes and standards. The detection and 6suppression methods for the category of fire hazards in the selected FAs were reviewed. The team compared the detector layout drawings against actual detector field locations and then reviewed those locations against NFPA Code 72E, "Automatic Fire Detectors," spacing and placement requirements.
The team evaluated the material condition and operational lineup of fire detection and suppression systems through in-plant observation of systems, design document reviews, and reference to the applicable NFPA codes and standards. The detection and suppression methods for the category of fire hazards in the selected FAs were reviewed.
 
The team compared the detector layout drawings against actual detector field locations and then reviewed those locations against NFPA Code 72E, Automatic Fire Detectors, spacing and placement requirements.


The preaction sprinkler system in Cable Spreading Room A (CSRA) was reviewed. This consisted of reviewing the system layout drawings against the field installation. Also, the hydraulic calculation was reviewed against the field installed configuration to ensure that the calculation bounded the installed configuration.
The preaction sprinkler system in Cable Spreading Room A (CSRA) was reviewed. This consisted of reviewing the system layout drawings against the field installation. Also, the hydraulic calculation was reviewed against the field installed configuration to ensure that the calculation bounded the installed configuration.


The team also reviewed fire brigade staffing, fire brigade response strategy, fire fighting pre-plans, fire brigade training, and the fire brigade drill program procedures. Particular attention was given to location and capacity of hose stations and approach routes to the FAs. The fire brigade equipment locker was inspected by the team. Documentation reviews were supplemented by discussions with persons responsible for fire brigade performance to assess the readiness of the fire brigade to suppress any and all fires that may occur.
The team also reviewed fire brigade staffing, fire brigade response strategy, fire fighting pre-plans, fire brigade training, and the fire brigade drill program procedures. Particular attention was given to location and capacity of hose stations and approach routes to the FAs. The fire brigade equipment locker was inspected by the team. Documentation reviews were supplemented by discussions with persons responsible for fire brigade performance to assess the readiness of the fire brigade to suppress any and all fires that may occur.


====b. Findings====
====b. Findings====
:  
:


=====Introduction:=====
=====Introduction:=====
The team identified a Green non-cited violation (NCV) of Shearon Harris Unit 1 operating license condition 2.F, for the licensee's failure to install the sprinkler system in CSRA in accordance with the approved FPP. Specifically, the installed system would not have been able to deliver the sprinkler system design density of 0.3 gallons per minute (gpm)/square foot (sq. ft.) in CSRA, as stated in the FPP in UFSAR Section 9.5.1.2.3.
The team identified a Green non-cited violation (NCV) of Shearon Harris Unit 1 operating license condition 2.F, for the licensees failure to install the sprinkler system in CSRA in accordance with the approved FPP. Specifically, the installed system would not have been able to deliver the sprinkler system design density of 0.3 gallons per minute (gpm)/square foot (sq. ft.) in CSRA, as stated in the FPP in UFSAR Section 9.5.1.2.3.


=====Description:=====
=====Description:=====
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UFSAR Section 9.5.1.2.3, Fire Protection (active systems), stated that sprinkler systems were provided to protect high hazards or vital process, storage and other operational areas and were designed in conformance with distribution system hydraulic calculations which determined water flow density and system pressure available to the protected areas. The UFSAR further stated that sprinkler system discharge densities were hydraulically designed to deliver 0.3 gpm/sq. ft. for the most remote areas of 3,000 sq. ft.
UFSAR Section 9.5.1.2.3, Fire Protection (active systems), stated that sprinkler systems were provided to protect high hazards or vital process, storage and other operational areas and were designed in conformance with distribution system hydraulic calculations which determined water flow density and system pressure available to the protected areas. The UFSAR further stated that sprinkler system discharge densities were hydraulically designed to deliver 0.3 gpm/sq. ft. for the most remote areas of 3,000 sq. ft.


or less. The licensee's hydraulic calculation for CSRA (FA 1-A-CSRA) was based on delivering a design density of 0.3 gpm/sq. ft. over an area of 3,000 sq. ft., with a maximum sprinkler head coverage area of 62 sq. ft. per sprinkler head. The hydraulic calculation was based on a maximum spacing between sprinkler heads of 8.0 ft. and a maximum spacing between sprinkler lines of 7.71 ft. The team performed a detailed review of the licensee's sprinkler layout drawings and field installation for CSRA and identified instances in the CSRA where the spacing between sprinkler heads on a branch line exceeded 8.0 ft. and the distance between sprinkler lines exceeded 7.71 ft. This resulted in the sprinkler head coverage area for a number of the sprinkler heads exceeding the maximum 62 sq. ft. per sprinkler head used in the calculation. The licensee's distribution system hydraulic calculation was not performed in accordance with the licensee's sprinkler system code of record (NFPA 13 - 1978 edition). The calculation used an incorrect value for the sprinkler head coverage area. The incorrect 7sprinkler head coverage area used in the hydraulic calculation resulted in some of the sprinkler heads on the system being unable to provide the required design density of 0.3 gpm/sq. ft. The team performed a comparison calculation to determine if the larger sprinkler head coverage area would have an impact on the capability of the sprinkler system to deliver the required design density. The comparison calculation identified that 12 of 44 sprinkler heads (approximately 27%) would not provide the design density of 0.3 gpm/sq. ft. as required by UFSAR Section 9.5.1.2.3. The team discussed this issue with licensee personnel who initiated NCR 297789 to address this issue in the corrective action program (CAP). Also, a continuous fire watch was established in CSRA as a compensatory measure in accordance with the Shearon Harris FPP.
or less. The licensees hydraulic calculation for CSRA (FA 1-A-CSRA) was based on delivering a design density of 0.3 gpm/sq. ft. over an area of 3,000 sq. ft., with a maximum sprinkler head coverage area of 62 sq. ft. per sprinkler head. The hydraulic calculation was based on a maximum spacing between sprinkler heads of 8.0 ft. and a maximum spacing between sprinkler lines of 7.71 ft. The team performed a detailed review of the licensees sprinkler layout drawings and field installation for CSRA and identified instances in the CSRA where the spacing between sprinkler heads on a branch line exceeded 8.0 ft. and the distance between sprinkler lines exceeded 7.71 ft.
 
This resulted in the sprinkler head coverage area for a number of the sprinkler heads exceeding the maximum 62 sq. ft. per sprinkler head used in the calculation. The licensees distribution system hydraulic calculation was not performed in accordance with the licensees sprinkler system code of record (NFPA 13 - 1978 edition). The calculation used an incorrect value for the sprinkler head coverage area. The incorrect sprinkler head coverage area used in the hydraulic calculation resulted in some of the sprinkler heads on the system being unable to provide the required design density of 0.3 gpm/sq. ft. The team performed a comparison calculation to determine if the larger sprinkler head coverage area would have an impact on the capability of the sprinkler system to deliver the required design density. The comparison calculation identified that 12 of 44 sprinkler heads (approximately 27%) would not provide the design density of 0.3 gpm/sq. ft. as required by UFSAR Section 9.5.1.2.3. The team discussed this issue with licensee personnel who initiated NCR 297789 to address this issue in the corrective action program (CAP). Also, a continuous fire watch was established in CSRA as a compensatory measure in accordance with the Shearon Harris FPP.


=====Analysis:=====
=====Analysis:=====
The licensee's failure to install the sprinkler system in CSRA in accordance with the approved FPP is a performance deficiency. This finding is more than minor because the installed sprinkler system degraded one of the fire protection defense in depth elements and it affected the reactor safety Mitigating Systems cornerstone objective. The team completed a Phase 2 screening of the finding in accordance with IMC 0609, Appendix F, Attachment 1, Part 2, Fire Protection SDP Phase 2 Worksheet, and concluded that the finding was of very low safety significance (Green) in accordance with Step 2.5, Task 2.5.5 of the Worksheet, because there was a safe shutdown path available which was independent of the FA of concern. The cause of this finding was not associated with a cross-cutting area because it is not reflective of current licensee performance.
The licensees failure to install the sprinkler system in CSRA in accordance with the approved FPP is a performance deficiency. This finding is more than minor because the installed sprinkler system degraded one of the fire protection defense in depth elements and it affected the reactor safety Mitigating Systems cornerstone objective. The team completed a Phase 2 screening of the finding in accordance with IMC 0609, Appendix F, Attachment 1, Part 2, Fire Protection SDP Phase 2 Worksheet, and concluded that the finding was of very low safety significance (Green) in accordance with Step 2.5, Task 2.5.5 of the Worksheet, because there was a safe shutdown path available which was independent of the FA of concern. The cause of this finding was not associated with a cross-cutting area because it is not reflective of current licensee performance.


=====Enforcement:=====
=====Enforcement:=====
Shearon Harris operating license condition 2.F. states in part that Carolina Power & Light Company shall implement and maintain in effect all provisions of the approved fire protection program as described in UFSAR Section 9.5.1 for the facility, as amended and as approved in the SER dated November 1983 (and Supplements 1 through 4), and the Safety Evaluation dated January 12, 1987.
Shearon Harris operating license condition 2.F. states in part that Carolina Power & Light Company shall implement and maintain in effect all provisions of the approved fire protection program as described in UFSAR Section 9.5.1 for the facility, as amended and as approved in the SER dated November 1983 (and Supplements 1 through 4), and the Safety Evaluation dated January 12, 1987.


UFSAR Section 9.5.1.2.3, Fire Protection (active systems), states that sprinkler system discharge densities are hydraulically designed to deliver 0.3 gpm/sq. ft. for the most remote areas of 3,000 sq. ft. or less.
UFSAR Section 9.5.1.2.3, Fire Protection (active systems), states that sprinkler system discharge densities are hydraulically designed to deliver 0.3 gpm/sq. ft. for the most remote areas of 3,000 sq. ft. or less.


Contrary to the above, on December 18, 2008, the team identified that the sprinkler system in CSRA was not installed in accordance with the FPP. Specifically, the installed system would not deliver the sprinkler system design density of 0.3 gpm/sq. ft. for the most remote areas of 3,000 sq. ft. or less, as stated in the FPP in UFSAR Section 9.5.1.2.3.
Contrary to the above, on December 18, 2008, the team identified that the sprinkler system in CSRA was not installed in accordance with the FPP. Specifically, the installed system would not deliver the sprinkler system design density of 0.3 gpm/sq. ft. for the most remote areas of 3,000 sq. ft. or less, as stated in the FPP in UFSAR Section 9.5.1.2.3. The licensees distribution system hydraulic calculation used an incorrect value for the sprinkler head coverage area which resulted in 12 of 44 sprinkler heads (approximately 27% of the sprinkler heads on the system) not being able to deliver the required design density of 0.3 gpm/sq. ft. The team determined that this condition has existed since at least 1987. The licensee entered this issue in the CAP as NCR 297789 and established a continuous fire watch in CSRA as a compensatory measure in accordance with the Shearon Harris FPP. Because this finding is of very low safety significance and was entered into the licensees corrective action program, this finding is being treated as a NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy.


The licensee's distribution system hydraulic calculation used an incorrect value for the sprinkler head coverage area which resulted in 12 of 44 sprinkler heads (approximately 27% of the sprinkler heads on the system) not being able to deliver the required design density of 0.3 gpm/sq. ft. The team determined that this condition has existed since at least 1987. The licensee entered this issue in the CAP as NCR 297789 and established a continuous fire watch in CSRA as a compensatory measure in accordance with the Shearon Harris FPP.
This finding is identified as NCV 05000400/2008008-01, Sprinkler System in Cable Spreading Room A Does Not Meet Licensees Fire Protection Program Requirements.


Because this finding is of very low safety significance and was entered into the licensee's corrective action program, this finding is being treated as a NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy. This finding is identified as NCV 05000400/2008008-01, Sprinkler System in Cable Spreading Room A Does Not Meet Licensee's Fire Protection Program Requirements.
===.05 Protection From Damage From Fire Suppression Activities===
 
8.05 Protection From Damage From Fire Suppression Activities


====a. Inspection Scope====
====a. Inspection Scope====
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====a. Inspection Scope====
====a. Inspection Scope====
Methodology The team reviewed the licensee's ability to implement an alternative shutdown strategy for the FA/FZ selected. The team reviewed the licensee's FPP program described in UFSAR Section 9.5.1; applicable sections of the SSA; AOPs; simplified flow diagrams; control wiring diagrams (CWDs); and other supporting documents for postulated fires in FA 12-A-CRC1/FZ 12-A-6-PICR1. The reviews focused on ensuring that the required functions for post-fire SSD and the corresponding equipment necessary to perform those functions were included in the procedures. The review included assessing whether hot and cold shutdown from outside the MCR could be implemented, and that transfer of control from the MCR to the auxiliary control panel (ACP) could be accomplished. This review also included verification that shutdown from outside the MCR could be performed both with and without the availability of offsite power.
Methodology The team reviewed the licensees ability to implement an alternative shutdown strategy for the FA/FZ selected. The team reviewed the licensees FPP program described in UFSAR Section 9.5.1; applicable sections of the SSA; AOPs; simplified flow diagrams; control wiring diagrams (CWDs); and other supporting documents for postulated fires in FA 12-A-CRC1/FZ 12-A-6-PICR1. The reviews focused on ensuring that the required functions for post-fire SSD and the corresponding equipment necessary to perform those functions were included in the procedures. The review included assessing whether hot and cold shutdown from outside the MCR could be implemented, and that transfer of control from the MCR to the auxiliary control panel (ACP) could be accomplished. This review also included verification that shutdown from outside the MCR could be performed both with and without the availability of offsite power.


Plant walkdowns were performed to verify that the plant configuration was consistent with that described in the SSA. These inspection activities focused on ensuring the adequacy of systems selected for reactivity control, reactor coolant makeup, reactor heat removal, process monitoring instrumentation, and support system functions. The team reviewed the systems and components credited for use during this shutdown method to verify that they would remain free from fire damage.
Plant walkdowns were performed to verify that the plant configuration was consistent with that described in the SSA. These inspection activities focused on ensuring the adequacy of systems selected for reactivity control, reactor coolant makeup, reactor heat removal, process monitoring instrumentation, and support system functions. The team reviewed the systems and components credited for use during this shutdown method to verify that they would remain free from fire damage.
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Operational Implementation The team reviewed training lesson plans and job performance measures for licensed and non-licensed operators to verify that the training reinforced the shutdown methodology in the SSA and AOPs for the selected FZ. The team also reviewed shift turnover logs and shift manning to verify that personnel required for SSD using the alternative shutdown systems and procedures were available on-site, exclusive of those assigned as fire brigade members.
Operational Implementation The team reviewed training lesson plans and job performance measures for licensed and non-licensed operators to verify that the training reinforced the shutdown methodology in the SSA and AOPs for the selected FZ. The team also reviewed shift turnover logs and shift manning to verify that personnel required for SSD using the alternative shutdown systems and procedures were available on-site, exclusive of those assigned as fire brigade members.


The team reviewed procedures utilized for post-fire SSD and performed a walk-through of procedure steps to ensure the implementation and human factors adequacy of the 9procedures. The team also reviewed selected operator actions to verify that the operators could reasonably be expected to perform the specific actions within the time required to maintain plant parameters within specified limits.
The team reviewed procedures utilized for post-fire SSD and performed a walk-through of procedure steps to ensure the implementation and human factors adequacy of the procedures. The team also reviewed selected operator actions to verify that the operators could reasonably be expected to perform the specific actions within the time required to maintain plant parameters within specified limits.


Time critical actions reviewed included: electrical power distribution alignment, establishing control at the ACP, establishing reactor coolant makeup, and establishing decay heat removal. The team reviewed and/or walked down applicable sections of procedure AOP-004, Remote Shutdown.
Time critical actions reviewed included: electrical power distribution alignment, establishing control at the ACP, establishing reactor coolant makeup, and establishing decay heat removal. The team reviewed and/or walked down applicable sections of procedure AOP-004, Remote Shutdown.
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The team reviewed cable routing data for a sample of SSD components referenced in AOP-004 to determine if the power and/or control circuits for the SSD components could be potentially damaged by a fire in FZ 12-A-6-PICR1. For those specific SSD components that had associated cables routed through the selected FZ, the team reviewed the CWDs to determine if those components and associated circuits were designed to be electrically isolated from fire damage such that they could be restored once the controls were transferred from the MCR to the ACP. The team also reviewed cable routing data for a sample of process monitoring instrument channels with indicators located on the ACP to verify that they would be unaffected by a fire in the selected FZ.
The team reviewed cable routing data for a sample of SSD components referenced in AOP-004 to determine if the power and/or control circuits for the SSD components could be potentially damaged by a fire in FZ 12-A-6-PICR1. For those specific SSD components that had associated cables routed through the selected FZ, the team reviewed the CWDs to determine if those components and associated circuits were designed to be electrically isolated from fire damage such that they could be restored once the controls were transferred from the MCR to the ACP. The team also reviewed cable routing data for a sample of process monitoring instrument channels with indicators located on the ACP to verify that they would be unaffected by a fire in the selected FZ.


The team also reviewed testing performed on the electrical circuits which are used to transfer controls from the MCR to the ACP. The test procedures and test records were reviewed to ensure that adequate tests were performed to verify the functionality of the alternative shutdown capability. The team also reviewed the test deficiencies to verify that they were correctly entered into the licensee's corrective action program. The components and documents reviewed are listed in the Attachment.
The team also reviewed testing performed on the electrical circuits which are used to transfer controls from the MCR to the ACP. The test procedures and test records were reviewed to ensure that adequate tests were performed to verify the functionality of the alternative shutdown capability. The team also reviewed the test deficiencies to verify that they were correctly entered into the licensees corrective action program. The components and documents reviewed are listed in the Attachment.


====b. Findings====
====b. Findings====


=====Introduction:=====
=====Introduction:=====
The team identified a noncompliance of very low safety significance with Shearon Harris Technical Specification 6.8.1.a, for inadequate procedural guidance which directed usage of instruments that were not protected from fire damage in FZ 12-A-6-PICR1. Specifically, procedure AOP-004, Remote Shutdown, directed the operators to verify emergency service water (ESW) header flows were above the minimum flow requirement of 7500 gpm using flow indicators (FI) FI-9101A2 and FI-9101B2. These instruments would be unreliable during operation from the ACP because their cables were routed through the FZ of concern and the cables were not protected from fire damage. The violation meets the criteria of NRC Enforcement Policy, "Interim Enforcement Policy Regarding Enforcement Discretion for Certain Fire Protection Issues (10 CFR 50.48)" for enforcement discretion.
The team identified a noncompliance of very low safety significance with Shearon Harris Technical Specification 6.8.1.a, for inadequate procedural guidance which directed usage of instruments that were not protected from fire damage in FZ 12-A-6-PICR1. Specifically, procedure AOP-004, Remote Shutdown, directed the operators to verify emergency service water (ESW) header flows were above the minimum flow requirement of 7500 gpm using flow indicators (FI) FI-9101A2 and FI-9101B2. These instruments would be unreliable during operation from the ACP because their cables were routed through the FZ of concern and the cables were not protected from fire damage. The violation meets the criteria of NRC Enforcement Policy, Interim Enforcement Policy Regarding Enforcement Discretion for Certain Fire Protection Issues (10 CFR 50.48) for enforcement discretion.


=====Description:=====
=====Description:=====
The team noted that procedure AOP-004, Remote Shutdown, would be used to safely shut down the plant from the ACP (utilizing Train B equipment) for a fire in FZ 12-A-6-PICR1. The procedure directed operators to verify ESW header (HDR) flows using FI-9101A2, A HDR Flow and FI-9101B2, B HDR Flow. The team reviewed cable routing data and noted that FI-9101A2 and FI-9101B2 may not provide reliable ESW flow indication for the operators at the ACP because the cables were routed through FZ 12-A-6-PICR1 and were not protected from fire damaged. This may potentially delay operator actions required to bring the plant to SSD conditions. Based on discussions with operations personnel and review of service water system simplified flow diagrams, the team determined that the ESW system was flow balanced to ensure that the 7500 10gpm minimum flow would be provided to ESW HDR A and ESW HDR B. During walkdowns of the ACP, the team noted that valve position indication (i.e., open/close) was provided at the ACP for various ESW valves, including 1SW-270, HDR A to Auxiliary Reservoir and 1SW-271, HDR B to Auxiliary Reservoir. These valves were required to be opened (from the ACP) to ensure adequate ESW header flow. Review of cable routing data for valve 1SW-271 showed that this valve was not routed through FZ 12-A-6-PICR1 and would not be affected by a postulated fire in this FZ. The team determined that, based on operator experience, training, and indication of the position of ESW valve 1SW-271 at the ACP, it was likely plant operators would be able to determine that sufficient ESW flow was available and they would take the appropriate actions required to ensure post-fire SSD conditions. The licensee initiated NCR 298072 to address this issue in the CAP.
The team noted that procedure AOP-004, Remote Shutdown, would be used to safely shut down the plant from the ACP (utilizing Train B equipment) for a fire in FZ 12-A-6-PICR1. The procedure directed operators to verify ESW header (HDR) flows using FI-9101A2, A HDR Flow and FI-9101B2, B HDR Flow. The team reviewed cable routing data and noted that FI-9101A2 and FI-9101B2 may not provide reliable ESW flow indication for the operators at the ACP because the cables were routed through FZ 12-A-6-PICR1 and were not protected from fire damaged. This may potentially delay operator actions required to bring the plant to SSD conditions. Based on discussions with operations personnel and review of service water system simplified flow diagrams, the team determined that the ESW system was flow balanced to ensure that the 7500 gpm minimum flow would be provided to ESW HDR A and ESW HDR B. During walkdowns of the ACP, the team noted that valve position indication (i.e., open/close)was provided at the ACP for various ESW valves, including 1SW-270, HDR A to Auxiliary Reservoir and 1SW-271, HDR B to Auxiliary Reservoir. These valves were required to be opened (from the ACP) to ensure adequate ESW header flow. Review of cable routing data for valve 1SW-271 showed that this valve was not routed through FZ 12-A-6-PICR1 and would not be affected by a postulated fire in this FZ. The team determined that, based on operator experience, training, and indication of the position of ESW valve 1SW-271 at the ACP, it was likely plant operators would be able to determine that sufficient ESW flow was available and they would take the appropriate actions required to ensure post-fire SSD conditions. The licensee initiated NCR 298072 to address this issue in the CAP.


=====Analysis:=====
=====Analysis:=====
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Contrary to the above, on October 10, 2008, the team identified that procedure AOP-004 provided inadequate guidance for monitoring ESW header flow at the ACP. Specifically, procedure AOP-004 directed the operators to verify ESW header flows were above the minimum flow requirement of 7500 gpm using flow indicators FI-9101A2, A HDR Flow and FI-9101B2, B HDR Flow. These instruments would be unreliable during operation from the ACP because their cables were routed through the FZ of concern and the cables were not protected from fire damage. The licensee initiated NCR 298072 to correct the procedure.
Contrary to the above, on October 10, 2008, the team identified that procedure AOP-004 provided inadequate guidance for monitoring ESW header flow at the ACP. Specifically, procedure AOP-004 directed the operators to verify ESW header flows were above the minimum flow requirement of 7500 gpm using flow indicators FI-9101A2, A HDR Flow and FI-9101B2, B HDR Flow. These instruments would be unreliable during operation from the ACP because their cables were routed through the FZ of concern and the cables were not protected from fire damage. The licensee initiated NCR 298072 to correct the procedure.


No enforcement action is required for the above noncompliance because pursuant to the Commission's Enforcement Policy and NRC Manual Chapter 0305, under certain conditions fire protection noncompliances at nuclear power plants that transition their licensing bases to 10 CFR 50.48(c) are eligible for enforcement and reactor oversight process (ROP) discretion. The Enforcement Policy and ROP also state that the noncompliance must not be evaluated as Red.
No enforcement action is required for the above noncompliance because pursuant to the Commissions Enforcement Policy and NRC Manual Chapter 0305, under certain conditions fire protection noncompliances at nuclear power plants that transition their licensing bases to 10 CFR 50.48(c) are eligible for enforcement and reactor oversight process (ROP) discretion. The Enforcement Policy and ROP also state that the noncompliance must not be evaluated as Red.


11Because the licensee committed, prior to December 31, 2005, to adopt NFPA 805 and change their fire protection licensing bases to comply with 10 CFR 50.48(c), the NRC is exercising enforcement discretion for this issue in accordance with the NRC Enforcement Policy, "Interim Enforcement Policy Regarding Enforcement Discretion for Certain Fire Protection Issues (10 CFR 50.48)."  Specifically, it was likely this issue would have been identified and addressed during the licensee's transition to NFPA 805, it was entered into the licensee's corrective action program and will be corrected, was not likely to have been previously identified by routine licensee efforts, was not willful, and was not associated with a finding of high safety significance.
Because the licensee committed, prior to December 31, 2005, to adopt NFPA 805 and change their fire protection licensing bases to comply with 10 CFR 50.48(c), the NRC is exercising enforcement discretion for this issue in accordance with the NRC Enforcement Policy, Interim Enforcement Policy Regarding Enforcement Discretion for Certain Fire Protection Issues (10 CFR 50.48). Specifically, it was likely this issue would have been identified and addressed during the licensees transition to NFPA 805, it was entered into the licensees corrective action program and will be corrected, was not likely to have been previously identified by routine licensee efforts, was not willful, and was not associated with a finding of high safety significance.


===.07 Circuit Analyses===
===.07 Circuit Analyses===


====a. Inspection Scope====
====a. Inspection Scope====
This segment is suspended for plants in transition because a more detailed review of cable routing and circuit analysis will be conducted as part of the fire protection program transition to NFPA 805. However, a review of the licensee's preliminary cable routing information was used by the team to assess the adequacy of the licensee's fire response procedures in the selected FAs/FZs. The routing information was based upon a list of SSD components submitted by the team.
This segment is suspended for plants in transition because a more detailed review of cable routing and circuit analysis will be conducted as part of the fire protection program transition to NFPA 805. However, a review of the licensees preliminary cable routing information was used by the team to assess the adequacy of the licensees fire response procedures in the selected FAs/FZs. The routing information was based upon a list of SSD components submitted by the team.


====b. Findings====
====b. Findings====
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====a. Inspection Scope====
====a. Inspection Scope====
The team reviewed the diverse plant communications systems that could be available and relied upon to support fire event notification, fire brigade fire fighting, and plant post-fire SSD. Specifically, the team reviewed the private automatic branch exchange system, which consisted of site telephones and their supporting equipment, the site paging system, the sound powered phone system and related equipment and connections, as well as the dedicated radio system and repeaters. The team conducted walkdowns of the plant communications systems in selected FAs/FZs to verify that equipment was properly staged for fire brigade and post-fire SSD activities and critical system components were readily available. The team also reviewed the cable routing for the radio repeaters and associated power sources. In addition, the team reviewed a sample of the surveillance records of maintenance periodic functional tests for the sound powered phones and radio systems. The team also reviewed the ARs that had been initiated for test failures to verify that the deficiencies were properly evaluated in accordance with the licensee's CAP. Additionally, the team reviewed AR 293578 that was initiated to address previously identified deficiencies in the sound powered phone system to ensure that appropriate corrective actions and compensatory measures were in place. The team reviewed the licensee's communications study to verify that the study was addressing the deficiencies as a part of the transition to NFPA 805.
The team reviewed the diverse plant communications systems that could be available and relied upon to support fire event notification, fire brigade fire fighting, and plant post-fire SSD. Specifically, the team reviewed the private automatic branch exchange system, which consisted of site telephones and their supporting equipment, the site paging system, the sound powered phone system and related equipment and connections, as well as the dedicated radio system and repeaters. The team conducted walkdowns of the plant communications systems in selected FAs/FZs to verify that equipment was properly staged for fire brigade and post-fire SSD activities and critical system components were readily available. The team also reviewed the cable routing for the radio repeaters and associated power sources. In addition, the team reviewed a sample of the surveillance records of maintenance periodic functional tests for the sound powered phones and radio systems. The team also reviewed the ARs that had been initiated for test failures to verify that the deficiencies were properly evaluated in accordance with the licensees CAP. Additionally, the team reviewed AR 293578 that was initiated to address previously identified deficiencies in the sound powered phone system to ensure that appropriate corrective actions and compensatory measures were in place. The team reviewed the licensees communications study to verify that the study was addressing the deficiencies as a part of the transition to NFPA 805.


====b. Findings====
====b. Findings====
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The team reviewed the emergency lighting system to verify that it was in accordance with 10 CFR 50.48, Operating License Condition 2.F, NRC SERs in NUREG 1038, and the UFSAR. The team conducted plant walkdowns of local manual operator actions identified in the post-fire SSD procedures to determine the adequacy of the emergency lighting units (ELUs) used to support plant personnel during post-fire SSD for the selected FAs/FZs. The team conducted walkdowns and observed the placement, alignment and coverage area of fixed 8-hour battery pack ELUs to evaluate their adequacy for illuminating access and egress pathways and any equipment requiring local operation and/or instrumentation monitoring for post-fire SSD.
The team reviewed the emergency lighting system to verify that it was in accordance with 10 CFR 50.48, Operating License Condition 2.F, NRC SERs in NUREG 1038, and the UFSAR. The team conducted plant walkdowns of local manual operator actions identified in the post-fire SSD procedures to determine the adequacy of the emergency lighting units (ELUs) used to support plant personnel during post-fire SSD for the selected FAs/FZs. The team conducted walkdowns and observed the placement, alignment and coverage area of fixed 8-hour battery pack ELUs to evaluate their adequacy for illuminating access and egress pathways and any equipment requiring local operation and/or instrumentation monitoring for post-fire SSD.


The manufacturer's information and vendor manuals for the installed 8-hour battery pack ELUs were reviewed to verify that the battery power supplies were rated with at least an 8-hour capacity as described in UFSAR Section 9.5.1. The team reviewed test records for the past year of periodic maintenance functional tests, as well as the annual capacity tests, to confirm that the batteries were being properly maintained and had the capacity to supply eight hours of lighting. The team reviewed the ARs that had been initiated for the identified test failures to verify that the deficiencies were evaluated, tracked, and corrected in accordance with the CAP. Additionally, the team reviewed lighting layout drawings and lighting panel details for the selected FAs/FZs to assess if the lighting circuits and sources used for the areas were diverse such that a fire in one of the areas would not affect the lighting required for SSD operations in other areas.
The manufacturers information and vendor manuals for the installed 8-hour battery pack ELUs were reviewed to verify that the battery power supplies were rated with at least an 8-hour capacity as described in UFSAR Section 9.5.1. The team reviewed test records for the past year of periodic maintenance functional tests, as well as the annual capacity tests, to confirm that the batteries were being properly maintained and had the capacity to supply eight hours of lighting. The team reviewed the ARs that had been initiated for the identified test failures to verify that the deficiencies were evaluated, tracked, and corrected in accordance with the CAP. Additionally, the team reviewed lighting layout drawings and lighting panel details for the selected FAs/FZs to assess if the lighting circuits and sources used for the areas were diverse such that a fire in one of the areas would not affect the lighting required for SSD operations in other areas.


====b. Findings====
====b. Findings====
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====a. Inspection Scope====
====a. Inspection Scope====
The team reviewed the licensee's SSA, FPP procedures, and conducted an electrical circuit analysis of the credited train of residual heat removal as a sample to verify the licensee's assertion that for damaged equipment repairs are not relied on to achieve post-fire cold shutdown. The team examined the cable routing with respect to the selected FAs/FZs to verify that the pump would be available for post-fire SSD without any necessary repairs. Based on this review, the team confirmed that the licensee's post-fire SSD procedures did not rely on cold shutdown repairs.
The team reviewed the licensees SSA, FPP procedures, and conducted an electrical circuit analysis of the credited train of residual heat removal as a sample to verify the licensees assertion that for damaged equipment repairs are not relied on to achieve post-fire cold shutdown. The team examined the cable routing with respect to the selected FAs/FZs to verify that the pump would be available for post-fire SSD without any necessary repairs. Based on this review, the team confirmed that the licensees post-fire SSD procedures did not rely on cold shutdown repairs.


====b. Findings====
====b. Findings====
No findings of significance were identified.
No findings of significance were identified.


13.11 Compensatory Measures
===.11 Compensatory Measures===


====a. Inspection Scope====
====a. Inspection Scope====
The team reviewed the administrative controls for out-of-service, degraded, and/or inoperable fire protection features (e.g., detection and suppression systems and equipment, passive fire barriers, or pumps, valves or electrical devices providing SSD functions or capabilities). The team reviewed selected items on the fire protection impairment log and compared them with the FAs/FZs selected for inspection. The compensatory measures that had been established in these areas/zones were compared to those specified for the applicable fire protection feature to verify that the risk associated with removing the fire protection feature from service was properly assessed and adequate compensatory measures were implemented in accordance with the approved FPP. Additionally, the team reviewed the licensee's short term compensatory measures (e.g., the continuous fire watch established for the degraded sprinkler system in CSRA) to verify that they were adequate to compensate for a degraded function or feature until appropriate corrective actions could be taken, and that the licensee was effective in returning the equipment to service in a reasonable period of time.
The team reviewed the administrative controls for out-of-service, degraded, and/or inoperable fire protection features (e.g., detection and suppression systems and equipment, passive fire barriers, or pumps, valves or electrical devices providing SSD functions or capabilities). The team reviewed selected items on the fire protection impairment log and compared them with the FAs/FZs selected for inspection. The compensatory measures that had been established in these areas/zones were compared to those specified for the applicable fire protection feature to verify that the risk associated with removing the fire protection feature from service was properly assessed and adequate compensatory measures were implemented in accordance with the approved FPP. Additionally, the team reviewed the licensees short term compensatory measures (e.g., the continuous fire watch established for the degraded sprinkler system in CSRA) to verify that they were adequate to compensate for a degraded function or feature until appropriate corrective actions could be taken, and that the licensee was effective in returning the equipment to service in a reasonable period of time.


====b. Findings====
====b. Findings====
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====a. Inspection Scope====
====a. Inspection Scope====
The team reviewed selected ARs and NCRs related to the Shearon Harris FPP to verify that items related to fire protection and SSD were appropriately entered into the licensee's CAP in accordance with the licensee's quality assurance program and procedural requirements. This review was conducted to assess the frequency of fire incidents and effectiveness of the fire prevention program and any maintenance-related or material condition problems related to fire incidents.
The team reviewed selected ARs and NCRs related to the Shearon Harris FPP to verify that items related to fire protection and SSD were appropriately entered into the licensees CAP in accordance with the licensees quality assurance program and procedural requirements. This review was conducted to assess the frequency of fire incidents and effectiveness of the fire prevention program and any maintenance-related or material condition problems related to fire incidents.


The team also reviewed other CAP documents, including completed corrective actions documented in selected ARs and NCRs, and operating experience program (OEP) documents to verify that industry-identified fire protection issues potentially or actually affecting Shearon Harris were appropriately entered into, and resolved by, the CAP process. Items included in the OEP effectiveness review were NRC regulatory issue summaries, information notices, generic letters, industry or vendor generated reports of noncompliances and defects under 10 CFR Part 21, and vendor information letters. Additionally, the team reviewed a sample of other identified issues. The documents reviewed are listed in the Attachment.
The team also reviewed other CAP documents, including completed corrective actions documented in selected ARs and NCRs, and operating experience program (OEP)documents to verify that industry-identified fire protection issues potentially or actually affecting Shearon Harris were appropriately entered into, and resolved by, the CAP process. Items included in the OEP effectiveness review were NRC regulatory issue summaries, information notices, generic letters, industry or vendor generated reports of noncompliances and defects under 10 CFR Part 21, and vendor information letters.
 
Additionally, the team reviewed a sample of other identified issues. The documents reviewed are listed in the Attachment.


====b. Findings====
====b. Findings====
No findings of significance were identified.
No findings of significance were identified.


144OA6  Meetings, Including Exit On October 10, 2008, the lead inspector presented the inspection results to Mr. C. Burton, Harris Plant Vice President, and other members of the licensee's staff. The licensee acknowledged the findings. Proprietary information is not included in this report. Following completion of additional reviews in the Region II office, another exit meeting was held by telephone with Mr. Burton and other members of his staff on December 18, 2008, to provide an update on changes to the preliminary inspection findings. The licensee acknowledged the findings.
{{a|4OA6}}
==4OA6 Meetings, Including Exit==
 
On October 10, 2008, the lead inspector presented the inspection results to Mr. C.
 
Burton, Harris Plant Vice President, and other members of the licensees staff. The licensee acknowledged the findings. Proprietary information is not included in this report. Following completion of additional reviews in the Region II office, another exit meeting was held by telephone with Mr. Burton and other members of his staff on December 18, 2008, to provide an update on changes to the preliminary inspection findings. The licensee acknowledged the findings.


ATTACHMENT:  
ATTACHMENT:  
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===Licensee personnel===
===Licensee personnel===
: [[contact::R. Atkins]], Reactor Operator  
: [[contact::R. Atkins]], Reactor Operator
: [[contact::C. Burton]], Vice President Harris Plant  
: [[contact::C. Burton]], Vice President Harris Plant
: [[contact::D. Corlett]], Supervisor, Licensing/Regulatory Programs  
: [[contact::D. Corlett]], Supervisor, Licensing/Regulatory Programs
: [[contact::M. Denny]], Engineering Supervisor, Equipment Performance  
: [[contact::M. Denny]], Engineering Supervisor, Equipment Performance
: [[contact::J. Doorhy]], Licensing Specialist, Licensing/Regulatory Programs  
: [[contact::J. Doorhy]], Licensing Specialist, Licensing/Regulatory Programs
: [[contact::J. Dufner]], Manager, Maintenance  
: [[contact::J. Dufner]], Manager, Maintenance
: [[contact::R. Duncan]], Vice President Nuclear Operations  
: [[contact::R. Duncan]], Vice President Nuclear Operations
: [[contact::J. Ertman]], Supervisor, Corporate Fire Protection  
: [[contact::J. Ertman]], Supervisor, Corporate Fire Protection
: [[contact::K. Harshaw]], Manager, Site Support Services  
: [[contact::K. Harshaw]], Manager, Site Support Services
: [[contact::K. Henderson]], Plant General Manager  
: [[contact::K. Henderson]], Plant General Manager
: [[contact::A. Holder]], Senior Engineering Technical Support Specialist, Corporate Engineering Support  
: [[contact::A. Holder]], Senior Engineering Technical Support Specialist, Corporate Engineering Support
: [[contact::G. Kilpatrick]], Training Manager  
: [[contact::G. Kilpatrick]], Training Manager
: [[contact::J. MacIntyre]], Fire Protection Engineer  
: [[contact::J. MacIntyre]], Fire Protection Engineer
: [[contact::L. Martin]], Superintendent, Design Engineering  
: [[contact::L. Martin]], Superintendent, Design Engineering
: [[contact::S. O'Connor]], Manager, Engineering  
: [[contact::S. OConnor]], Manager, Engineering
: [[contact::A. Pearson]], Fire Protection Engineer  
: [[contact::A. Pearson]], Fire Protection Engineer
: [[contact::J. Pierce]], Manager, Nuclear Assessment Section  
: [[contact::J. Pierce]], Manager, Nuclear Assessment Section
: [[contact::B. Rhodes]], Lead Engineer, Fire Protection Team  
: [[contact::B. Rhodes]], Lead Engineer, Fire Protection Team
: [[contact::S. Saunders]], Superintendent, Systems Engineering  
: [[contact::S. Saunders]], Superintendent, Systems Engineering
: [[contact::A. Zimmerman]], Licensing Specialist, Licensing/Regulatory Programs  
: [[contact::A. Zimmerman]], Licensing Specialist, Licensing/Regulatory Programs
===NRC personnel===
===NRC personnel===
: [[contact::K. Korth]], Acting Senior Resident Inspector  
: [[contact::K. Korth]], Acting Senior Resident Inspector
: [[contact::P. Lessard]], Resident Inspector  
: [[contact::P. Lessard]], Resident Inspector
: [[contact::R. Musser]], Chief, Reactor Projects Branch 4, Division of Reactor Projects  
: [[contact::R. Musser]], Chief, Reactor Projects Branch 4, Division of Reactor Projects
: [[contact::R. Nease]], Chief, Engineering Branch 2, Division of Reactor Safety  
: [[contact::R. Nease]], Chief, Engineering Branch 2, Division of Reactor Safety
: [[contact::M. Pribish]], Acting Senior Resident Inspector  
: [[contact::M. Pribish]], Acting Senior Resident Inspector


==LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED==
==LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED==


===Opened/Closed===
===Opened/Closed===
: 05000400/2008008-01 NCV Sprinkler System in Cable Spreading Room A Does       Not Meet Licensee's Fire Protection Program Requirements (Section 1R05.04)  
: 05000400/2008008-01                   NCV   Sprinkler System in Cable Spreading Room A Does Not Meet Licensees Fire Protection Program Requirements (Section 1R05.04)


==LIST OF DOCUMENTS REVIEWED==
==LIST OF DOCUMENTS REVIEWED==


}}
}}

Revision as of 10:16, 14 November 2019

IR 05000400-08-008, on 09/22-26/2008 and 10/06-10/2008, Shearon Harris Nuclear Power Plant, Unit 1; Triennial Fire Protection Inspection
ML083570209
Person / Time
Site: Harris Duke Energy icon.png
Issue date: 12/19/2008
From: Nease R
NRC/RGN-II/DRS/EB2
To: Burton C
Carolina Power & Light Co
References
IR-08-008
Download: ML083570209 (28)
v • d • e


Text

UNITED STATES NUCLEAR REGULATORY COMMISSION December 19, 2008

SUBJECT:

SHEARON HARRIS NUCLEAR POWER PLANT - NRC TRIENNIAL FIRE PROTECTION INSPECTION REPORT 05000400/2008008 AND EXERCISE OF ENFORCEMENT DISCRETION

Dear Mr. Burton:

On October 10, 2008, the U.S. Nuclear Regulatory Commission (NRC) completed a triennial fire protection inspection at your Shearon Harris Nuclear Plant. The enclosed inspection report documents the inspection results, which were discussed on October 10, 2008, with you and other members of your staff. Following completion of additional review in the Region II office, another exit meeting was held by telephone with you and other members of your staff on December 18, 2008, to provide an update on changes to the preliminary inspection findings.

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

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

This report documents one NRC-identified finding of very low safety significance (Green) which was determined to involve a violation of NRC requirements. However, because of the very low safety significance and because it was entered into your corrective action program, the NRC is treating this finding as a non-cited violation (NCV) consistent with Section VI.A.1 of the NRC Enforcement Policy. If you contest any NCV in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory Commission, ATTN.: Document Control Desk, Washington, DC 20555-0001; with copies to the Regional Administrator, Region II; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at the Shearon Harris site.

In addition, the enclosed report documents one noncompliance that was identified during the inspection for which the NRC is exercising enforcement discretion. The NRC is not taking any enforcement action for this noncompliance because it meets the criteria of the NRC Enforcement Policy, Interim Enforcement Policy Regarding Enforcement Discretion for Certain Fire Protection Issues (10 CFR 50.48), and NRC Inspection Manual Chapter 0305, Violations in Specified Areas of Interest Qualifying for Enforcement Discretion.

CP&L 2 In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records 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: Paul fillion for/

Rebecca L. Nease, Chief, Engineering Branch 2 Division of Reactor Safety Docket No.: 50-400 License No.: NPF-63

Enclosure:

Inspection Report 05000400/2008008 w/Attachment: Supplemental Information

REGION II==

Docket No.: 50-400 License No.: NPF-63 Report No.: 05000400/2008008 Licensee: Carolina Power and Light Company Facility: Shearon Harris Nuclear Power Plant, Unit 1 Location: New Hill, North Carolina Dates: September 22-26, 2008 (Week 1)

October 6-10, 2008 (Week 2)

Inspectors: M. Thomas, Senior Reactor Inspector (Team Lead)

O. Lopez, Fire Protection Inspector in Training B. Melly, Fire Protection Engineer (Consultant)

N. Merriweather, Senior Reactor Inspector K. Miller, Reactor Inspector in Training N. Staples, Reactor Inspector L. Suggs, Reactor Inspector Approved by: Rebecca L. Nease, Chief Engineering Branch 2 Division of Reactor Safety Enclosure

SUMMARY OF FINDINGS

IR 05000400/2008008; 09/22-26/2008 and 10/06-10/2008; Shearon Harris Nuclear Power Plant,

Unit 1; Triennial Fire Protection Inspection.

This report covers an announced two-week triennial fire protection inspection by a team of four regional inspectors and one contract inspector. One Green non-cited violation 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'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.

NRC-Identified and Self-Revealing Findings

Cornerstone: Mitigating Systems

  • Green: The team identified a non-cited violation of Shearon Harris Unit 1 operating license condition 2.F, for the licensees failure to install the sprinkler system in Cable Spreading Room A (CSRA) in accordance with the approved fire protection program (FPP). Specifically, the installed system would not have been able to deliver the sprinkler system design density of 0.3 gallons per minute/square foot in CSRA, as stated in the FPP in Updated Final Safety Analysis Report Section 9.5.1.2.3. The licensee entered this issue in the corrective action program and established a continuous fire watch in CSRA as a compensatory measure in accordance with the Shearon Harris FPP.

The licensees failure to install the sprinkler system in CSRA in accordance with the approved FPP is a performance deficiency. This finding is more than minor because the installed sprinkler system degraded one of the fire protection defense in depth elements and it affected the reactor safety Mitigating Systems cornerstone objective.

The team completed a Phase 2 screening of the finding in accordance with IMC 0609, Appendix F, Attachment 1, Part 2, Fire Protection SDP Phase 2 Worksheet, and concluded that the finding was of very low safety significance (Green), in accordance with Step 2.5, Task 2.5.5 of the Worksheet, because there was a safe shutdown path available which was independent of CSRA. The cause of this finding was not associated with a cross-cutting area because it is not reflective of current licensee performance. (Section 1R05.04)

Licensee-Identified Violations

None.

REPORT DETAILS

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity

1R05 Fire Protection

This report presents the results of a triennial fire protection inspection for a plant in transition to National Fire Protection Association (NFPA) Standard 805, Performance-Based Standard for Fire Protection for Light Water Reactor Electric Generating Plants, 2001 Edition. This inspection was conducted in accordance with NRC Inspection Procedure (IP) 71111.05TTP, Fire Protection-NFPA 805 Transition Period (Triennial).

The objective of the inspection was to review the Shearon Harris Unit 1 FPP for selected risk-significant fire areas (FAs)/fire zones (FZs). The team selected three FAs for detailed review to examine the licensees implementation of the FPP. The three FAs were selected based on risk insights from the licensees Individual Plant Examination for External Events, information contained in FPP documents, results of prior NRC triennial fire protection inspections, and in-plant walk downs by the team. Section 71111.05-05 of the IP specifies a minimum sample size of three FAs. Detailed inspection of these three FAs fulfills the procedure completion criteria. The three FAs selected were:

  • FA 1-A-CSRA, Cable Spread Room A, Reactor Auxiliary Building (RAB), 286 foot (ft.) elevation.
  • FA 1-A-SWGRA, Switchgear Room A, RAB 286 ft. elevation.
  • FA 12-A-CRC1/FZ 12-A-6-PICR1, Control Room Complex, Process Instrument Cabinet Room, RAB 305 ft. elevation.

The team evaluated the licensees FPP against applicable requirements, including Operating License Condition 2.F; Title 10 of the Code of Federal Regulations, Part 50.48 (10 CFR 50.48); commitments to NRC Branch Technical Position (BTP) Chemical Engineering Branch (CMEB) 9.5-1, Guidelines for Fire Protection for Nuclear Power Plants; Shearon Harris Updated Final Safety Analysis Report (UFSAR); related NRC safety evaluation reports (SERs) including all applicable supplements; NRC Safety Evaluation dated January 12, 1987; and plant Technical Specifications. The team evaluated each selected FA/FZ against these requirements. The specific documents reviewed by the team are listed in the Attachment to this inspection report.

.01 Post-Fire Safe Shutdown From Main Control Room (Normal Shutdown)

a. Inspection Scope

Methodology The team reviewed the licensees FPP described in UFSAR Section 9.5.1; NRC SER dated November 1983 (and Supplements 1 through 4); applicable sections of the licensees post-fire safe shutdown analysis (SSA); plant procedures; simplified flow diagrams; electrical drawings; and other supporting documents. The reviews were performed to verify that hot and cold shutdown could be achieved and maintained from the main control room (MCR) for postulated fires in FAs 1-A-CSRA and 1-A-SWGRA.

This review also included verification that shutdown from the MCR could be performed both with and without the availability of offsite power. Plant walkdowns were performed to verify that the plant configuration was consistent with that described in the fire hazards analysis and the SSA. The inspection activities focused on ensuring the adequacy of systems selected for reactivity control, reactor coolant makeup, reactor heat removal, process monitoring instrumentation, and support system functions. The team reviewed the systems and components credited for use during this shutdown method to verify that they would remain free from fire damage.

Operational Implementation The team reviewed the adequacy of procedures utilized for post-fire safe shutdown and performed a walk through of procedure steps to ensure the implementation and human factors adequacy of the procedures. The team also reviewed selected operator actions to verify that the operators could reasonably be expected to perform the specific actions within the time required to maintain plant parameters within specified limits.

The team reviewed cable routing data for a sample of safe shutdown (SSD) components to determine if the power and/or control circuits for the SSD components could be potentially damaged by a fire in any of the FAs selected. The team reviewed and/or walked down applicable sections of the following abnormal operating procedures (AOPs)for FAs 1-A-CSRA and 1-A-SWGRA.

  • AOP-036.08, Fire Areas: 1-A-SWGRA, 1-A-SWGRB The team reviewed local operator manual actions to ensure that the actions could be implemented in accordance with plant procedures in the times necessary to support the SSD method for the applicable FA and to verify that those actions met the criteria in 2 of NRC IP 71111.05TTP. The team reviewed the existing manual action required for hot standby that were specified in the licensees SSA. The team also reviewed licensee nuclear condition report (NCR) 205333, which was initiated to assess and track resolution of the operator manual action issue as part of the plant-wide risk evaluation during the transition to NFPA 805.

b. Findings

No findings of significance were identified.

.02 Protection of Safe Shutdown Capabilities

a. Inspection Scope

The team reviewed the fire protection features used to protect safe shutdown cables and components to ensure they satisfy the separation and design requirements specified in the BTP CMEB 9.5-1 and implemented by the licensee in UFSAR Section 9.5.1 and the licensees SSA (Calculation E-5525).

The team reviewed those portions of the UFSAR dealing with the safe shutdown. One objective of this review was to evaluate the completeness and depth of the analysis which determined the strategy for protecting the various system functions necessary to achieve and maintain hot standby, accomplish long term cool down and achieve cold shutdown following a severe fire.

Through a combination of design information review and in-plant inspection, the team ascertained whether the fire protection features in place to protect SSD capability satisfied the separation and design requirements specified in BTP CMEB 9.5-1 (e.g., a FA with one-hour fire barriers around the SSD cables together with area wide automatic suppression and detection would meet the requirements).

b. Findings

No findings of significance were identified.

.03 Passive Fire Protection

a. Inspection Scope

The team inspected the material condition and fire rating of the fire area boundaries of the selected FAs/FZs and electrical raceway fire barrier systems inside the selected FAs/FZs to ensure that they were appropriate for the fire hazards in the area. Barriers reviewed included reinforced concrete walls/floors/ceilings, masonry block walls, Thermo-Lag 330-1 walls, mechanical and electrical penetration seals, doors, dampers and HEMYC wrap. Construction details and fire endurance test data which established the ratings of these fire barriers were reviewed. Engineering evaluations related to fire barriers were also reviewed. Where applicable, the team examined installed barriers to compare the configuration of the barrier to the rated configuration. The overall criterion applied to this element of the inspection procedure was that the passive fire barriers had the capability to contain fires for one hour or three hours as applicable.

The team reviewed the station penetration seal program and selected seals during plant walkdowns to verify that the penetration seal engineering designs could be traced back to qualified fire tests that support the penetration seals rating.

The team reviewed the licensees responses (dated April 28, 2006, and June 9, 2006) to Generic Letter 2006-03, Potentially Nonconforming HEMYC and MT Fire Barrier Configurations, to verify that compensatory measures were in place until resolution of the degraded fire barriers is accomplished during the licensees transition process to NFPA 805.

b. Findings

No findings of significance were identified.

.04 Active Fire Protection

a. Inspection Scope

The team evaluated the material condition and operational lineup of fire detection and suppression systems through in-plant observation of systems, design document reviews, and reference to the applicable NFPA codes and standards. The detection and suppression methods for the category of fire hazards in the selected FAs were reviewed.

The team compared the detector layout drawings against actual detector field locations and then reviewed those locations against NFPA Code 72E, Automatic Fire Detectors, spacing and placement requirements.

The preaction sprinkler system in Cable Spreading Room A (CSRA) was reviewed. This consisted of reviewing the system layout drawings against the field installation. Also, the hydraulic calculation was reviewed against the field installed configuration to ensure that the calculation bounded the installed configuration.

The team also reviewed fire brigade staffing, fire brigade response strategy, fire fighting pre-plans, fire brigade training, and the fire brigade drill program procedures. Particular attention was given to location and capacity of hose stations and approach routes to the FAs. The fire brigade equipment locker was inspected by the team. Documentation reviews were supplemented by discussions with persons responsible for fire brigade performance to assess the readiness of the fire brigade to suppress any and all fires that may occur.

b. Findings

Introduction:

The team identified a Green non-cited violation (NCV) of Shearon Harris Unit 1 operating license condition 2.F, for the licensees failure to install the sprinkler system in CSRA in accordance with the approved FPP. Specifically, the installed system would not have been able to deliver the sprinkler system design density of 0.3 gallons per minute (gpm)/square foot (sq. ft.) in CSRA, as stated in the FPP in UFSAR Section 9.5.1.2.3.

Description:

During review of the preaction sprinkler system in the CSRA, the team identified that the hydraulic calculation was incorrect and the installed system would not deliver the sprinkler system design density of 0.3 gpm/sq. ft. for the most remote areas of 3,000 sq. ft. or less, as stated in the UFSAR.

UFSAR Section 9.5.1.2.3, Fire Protection (active systems), stated that sprinkler systems were provided to protect high hazards or vital process, storage and other operational areas and were designed in conformance with distribution system hydraulic calculations which determined water flow density and system pressure available to the protected areas. The UFSAR further stated that sprinkler system discharge densities were hydraulically designed to deliver 0.3 gpm/sq. ft. for the most remote areas of 3,000 sq. ft.

or less. The licensees hydraulic calculation for CSRA (FA 1-A-CSRA) was based on delivering a design density of 0.3 gpm/sq. ft. over an area of 3,000 sq. ft., with a maximum sprinkler head coverage area of 62 sq. ft. per sprinkler head. The hydraulic calculation was based on a maximum spacing between sprinkler heads of 8.0 ft. and a maximum spacing between sprinkler lines of 7.71 ft. The team performed a detailed review of the licensees sprinkler layout drawings and field installation for CSRA and identified instances in the CSRA where the spacing between sprinkler heads on a branch line exceeded 8.0 ft. and the distance between sprinkler lines exceeded 7.71 ft.

This resulted in the sprinkler head coverage area for a number of the sprinkler heads exceeding the maximum 62 sq. ft. per sprinkler head used in the calculation. The licensees distribution system hydraulic calculation was not performed in accordance with the licensees sprinkler system code of record (NFPA 13 - 1978 edition). The calculation used an incorrect value for the sprinkler head coverage area. The incorrect sprinkler head coverage area used in the hydraulic calculation resulted in some of the sprinkler heads on the system being unable to provide the required design density of 0.3 gpm/sq. ft. The team performed a comparison calculation to determine if the larger sprinkler head coverage area would have an impact on the capability of the sprinkler system to deliver the required design density. The comparison calculation identified that 12 of 44 sprinkler heads (approximately 27%) would not provide the design density of 0.3 gpm/sq. ft. as required by UFSAR Section 9.5.1.2.3. The team discussed this issue with licensee personnel who initiated NCR 297789 to address this issue in the corrective action program (CAP). Also, a continuous fire watch was established in CSRA as a compensatory measure in accordance with the Shearon Harris FPP.

Analysis:

The licensees failure to install the sprinkler system in CSRA in accordance with the approved FPP is a performance deficiency. This finding is more than minor because the installed sprinkler system degraded one of the fire protection defense in depth elements and it affected the reactor safety Mitigating Systems cornerstone objective. The team completed a Phase 2 screening of the finding in accordance with IMC 0609, Appendix F, Attachment 1, Part 2, Fire Protection SDP Phase 2 Worksheet, and concluded that the finding was of very low safety significance (Green) in accordance with Step 2.5, Task 2.5.5 of the Worksheet, because there was a safe shutdown path available which was independent of the FA of concern. The cause of this finding was not associated with a cross-cutting area because it is not reflective of current licensee performance.

Enforcement:

Shearon Harris operating license condition 2.F. states in part that Carolina Power & Light Company shall implement and maintain in effect all provisions of the approved fire protection program as described in UFSAR Section 9.5.1 for the facility, as amended and as approved in the SER dated November 1983 (and Supplements 1 through 4), and the Safety Evaluation dated January 12, 1987.

UFSAR Section 9.5.1.2.3, Fire Protection (active systems), states that sprinkler system discharge densities are hydraulically designed to deliver 0.3 gpm/sq. ft. for the most remote areas of 3,000 sq. ft. or less.

Contrary to the above, on December 18, 2008, the team identified that the sprinkler system in CSRA was not installed in accordance with the FPP. Specifically, the installed system would not deliver the sprinkler system design density of 0.3 gpm/sq. ft. for the most remote areas of 3,000 sq. ft. or less, as stated in the FPP in UFSAR Section 9.5.1.2.3. The licensees distribution system hydraulic calculation used an incorrect value for the sprinkler head coverage area which resulted in 12 of 44 sprinkler heads (approximately 27% of the sprinkler heads on the system) not being able to deliver the required design density of 0.3 gpm/sq. ft. The team determined that this condition has existed since at least 1987. The licensee entered this issue in the CAP as NCR 297789 and established a continuous fire watch in CSRA as a compensatory measure in accordance with the Shearon Harris FPP. Because this finding is of very low safety significance and was entered into the licensees corrective action program, this finding is being treated as a NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy.

This finding is identified as NCV 05000400/2008008-01, Sprinkler System in Cable Spreading Room A Does Not Meet Licensees Fire Protection Program Requirements.

.05 Protection From Damage From Fire Suppression Activities

a. Inspection Scope

Through a combination of in-plant inspection and drawing reviews, the team evaluated the selected FAs/FZs to determine whether redundant trains of systems required for post-fire SSD could be subject to damage from fire suppression activities or from the rupture or inadvertent operation of fire suppression systems. The team considered the effects of water, drainage, heat, hot gasses, and smoke that could potentially damage redundant trains.

b. Findings

No findings of significance were identified.

.06 Post-Fire Safe Shutdown From Outside the Main Control Room (Alternative Shutdown)

a. Inspection Scope

Methodology The team reviewed the licensees ability to implement an alternative shutdown strategy for the FA/FZ selected. The team reviewed the licensees FPP program described in UFSAR Section 9.5.1; applicable sections of the SSA; AOPs; simplified flow diagrams; control wiring diagrams (CWDs); and other supporting documents for postulated fires in FA 12-A-CRC1/FZ 12-A-6-PICR1. The reviews focused on ensuring that the required functions for post-fire SSD and the corresponding equipment necessary to perform those functions were included in the procedures. The review included assessing whether hot and cold shutdown from outside the MCR could be implemented, and that transfer of control from the MCR to the auxiliary control panel (ACP) could be accomplished. This review also included verification that shutdown from outside the MCR could be performed both with and without the availability of offsite power.

Plant walkdowns were performed to verify that the plant configuration was consistent with that described in the SSA. These inspection activities focused on ensuring the adequacy of systems selected for reactivity control, reactor coolant makeup, reactor heat removal, process monitoring instrumentation, and support system functions. The team reviewed the systems and components credited for use during this shutdown method to verify that they would remain free from fire damage.

Operational Implementation The team reviewed training lesson plans and job performance measures for licensed and non-licensed operators to verify that the training reinforced the shutdown methodology in the SSA and AOPs for the selected FZ. The team also reviewed shift turnover logs and shift manning to verify that personnel required for SSD using the alternative shutdown systems and procedures were available on-site, exclusive of those assigned as fire brigade members.

The team reviewed procedures utilized for post-fire SSD and performed a walk-through of procedure steps to ensure the implementation and human factors adequacy of the procedures. The team also reviewed selected operator actions to verify that the operators could reasonably be expected to perform the specific actions within the time required to maintain plant parameters within specified limits.

Time critical actions reviewed included: electrical power distribution alignment, establishing control at the ACP, establishing reactor coolant makeup, and establishing decay heat removal. The team reviewed and/or walked down applicable sections of procedure AOP-004, Remote Shutdown.

The team reviewed cable routing data for a sample of SSD components referenced in AOP-004 to determine if the power and/or control circuits for the SSD components could be potentially damaged by a fire in FZ 12-A-6-PICR1. For those specific SSD components that had associated cables routed through the selected FZ, the team reviewed the CWDs to determine if those components and associated circuits were designed to be electrically isolated from fire damage such that they could be restored once the controls were transferred from the MCR to the ACP. The team also reviewed cable routing data for a sample of process monitoring instrument channels with indicators located on the ACP to verify that they would be unaffected by a fire in the selected FZ.

The team also reviewed testing performed on the electrical circuits which are used to transfer controls from the MCR to the ACP. The test procedures and test records were reviewed to ensure that adequate tests were performed to verify the functionality of the alternative shutdown capability. The team also reviewed the test deficiencies to verify that they were correctly entered into the licensees corrective action program. The components and documents reviewed are listed in the Attachment.

b. Findings

Introduction:

The team identified a noncompliance of very low safety significance with Shearon Harris Technical Specification 6.8.1.a, for inadequate procedural guidance which directed usage of instruments that were not protected from fire damage in FZ 12-A-6-PICR1. Specifically, procedure AOP-004, Remote Shutdown, directed the operators to verify emergency service water (ESW) header flows were above the minimum flow requirement of 7500 gpm using flow indicators (FI) FI-9101A2 and FI-9101B2. These instruments would be unreliable during operation from the ACP because their cables were routed through the FZ of concern and the cables were not protected from fire damage. The violation meets the criteria of NRC Enforcement Policy, Interim Enforcement Policy Regarding Enforcement Discretion for Certain Fire Protection Issues (10 CFR 50.48) for enforcement discretion.

Description:

The team noted that procedure AOP-004, Remote Shutdown, would be used to safely shut down the plant from the ACP (utilizing Train B equipment) for a fire in FZ 12-A-6-PICR1. The procedure directed operators to verify ESW header (HDR) flows using FI-9101A2, A HDR Flow and FI-9101B2, B HDR Flow. The team reviewed cable routing data and noted that FI-9101A2 and FI-9101B2 may not provide reliable ESW flow indication for the operators at the ACP because the cables were routed through FZ 12-A-6-PICR1 and were not protected from fire damaged. This may potentially delay operator actions required to bring the plant to SSD conditions. Based on discussions with operations personnel and review of service water system simplified flow diagrams, the team determined that the ESW system was flow balanced to ensure that the 7500 gpm minimum flow would be provided to ESW HDR A and ESW HDR B. During walkdowns of the ACP, the team noted that valve position indication (i.e., open/close)was provided at the ACP for various ESW valves, including 1SW-270, HDR A to Auxiliary Reservoir and 1SW-271, HDR B to Auxiliary Reservoir. These valves were required to be opened (from the ACP) to ensure adequate ESW header flow. Review of cable routing data for valve 1SW-271 showed that this valve was not routed through FZ 12-A-6-PICR1 and would not be affected by a postulated fire in this FZ. The team determined that, based on operator experience, training, and indication of the position of ESW valve 1SW-271 at the ACP, it was likely plant operators would be able to determine that sufficient ESW flow was available and they would take the appropriate actions required to ensure post-fire SSD conditions. The licensee initiated NCR 298072 to address this issue in the CAP.

Analysis:

The team determined that the inadequate SSD procedure guidance is a performance deficiency. This noncompliance is considered to be more than minor because it is associated with the procedure quality attribute of the Mitigating Systems cornerstone and it affected the cornerstone objective of protection against external events, i.e., fire. The inspectors assessed the noncompliance using IMC 0609, Appendix F, Fire Protection Significance Determination Process. This noncompliance was determined to be of very low safety significance (Green) using Appendix F of the Significance Determination Process (SDP), because it did not adversely affect components credited for reactivity control, reactor coolant makeup, reactor heat removal, and support systems functions. The team determined that based on experience, training, and ESW valve 1SW-271 position indication available at the ACP, it is likely plant operators would be able to determine that sufficient ESW flow was available and they would take the appropriate actions required to ensure post-fire SSD conditions.

Enforcement:

Technical Specification 6.8.1.a. requires that written procedures shall be established, implemented, and maintained covering the activities in Appendix A of Regulatory Guide 1.33, Revision 2, dated February 1978. Regulatory Guide 1.33, Appendix A, Section 6.v., requires procedures for combating emergencies such as plant fires. AOP-004, Remote Shutdown, Rev. 42, provided instructions for placing Shearon Harris Unit 1 in a safe condition if operations could not be performed from the MCR due to a fire in the process instrument cabinet room (FZ 12-A-6-PICR1).

Contrary to the above, on October 10, 2008, the team identified that procedure AOP-004 provided inadequate guidance for monitoring ESW header flow at the ACP. Specifically, procedure AOP-004 directed the operators to verify ESW header flows were above the minimum flow requirement of 7500 gpm using flow indicators FI-9101A2, A HDR Flow and FI-9101B2, B HDR Flow. These instruments would be unreliable during operation from the ACP because their cables were routed through the FZ of concern and the cables were not protected from fire damage. The licensee initiated NCR 298072 to correct the procedure.

No enforcement action is required for the above noncompliance because pursuant to the Commissions Enforcement Policy and NRC Manual Chapter 0305, under certain conditions fire protection noncompliances at nuclear power plants that transition their licensing bases to 10 CFR 50.48(c) are eligible for enforcement and reactor oversight process (ROP) discretion. The Enforcement Policy and ROP also state that the noncompliance must not be evaluated as Red.

Because the licensee committed, prior to December 31, 2005, to adopt NFPA 805 and change their fire protection licensing bases to comply with 10 CFR 50.48(c), the NRC is exercising enforcement discretion for this issue in accordance with the NRC Enforcement Policy, Interim Enforcement Policy Regarding Enforcement Discretion for Certain Fire Protection Issues (10 CFR 50.48). Specifically, it was likely this issue would have been identified and addressed during the licensees transition to NFPA 805, it was entered into the licensees corrective action program and will be corrected, was not likely to have been previously identified by routine licensee efforts, was not willful, and was not associated with a finding of high safety significance.

.07 Circuit Analyses

a. Inspection Scope

This segment is suspended for plants in transition because a more detailed review of cable routing and circuit analysis will be conducted as part of the fire protection program transition to NFPA 805. However, a review of the licensees preliminary cable routing information was used by the team to assess the adequacy of the licensees fire response procedures in the selected FAs/FZs. The routing information was based upon a list of SSD components submitted by the team.

b. Findings

A noncompliance of very low safety significance regarding fire response procedural guidance which directed operators to verify ESW flow using flow indicators at the ACP that had cables routed through the FZ of concern is discussed in Section 1R05.06.b. of this inspection report.

.08 Communications

a. Inspection Scope

The team reviewed the diverse plant communications systems that could be available and relied upon to support fire event notification, fire brigade fire fighting, and plant post-fire SSD. Specifically, the team reviewed the private automatic branch exchange system, which consisted of site telephones and their supporting equipment, the site paging system, the sound powered phone system and related equipment and connections, as well as the dedicated radio system and repeaters. The team conducted walkdowns of the plant communications systems in selected FAs/FZs to verify that equipment was properly staged for fire brigade and post-fire SSD activities and critical system components were readily available. The team also reviewed the cable routing for the radio repeaters and associated power sources. In addition, the team reviewed a sample of the surveillance records of maintenance periodic functional tests for the sound powered phones and radio systems. The team also reviewed the ARs that had been initiated for test failures to verify that the deficiencies were properly evaluated in accordance with the licensees CAP. Additionally, the team reviewed AR 293578293578that was initiated to address previously identified deficiencies in the sound powered phone system to ensure that appropriate corrective actions and compensatory measures were in place. The team reviewed the licensees communications study to verify that the study was addressing the deficiencies as a part of the transition to NFPA 805.

b. Findings

No findings of significance were identified.

.09 Emergency Lighting

a. Inspection Scope

The team reviewed the emergency lighting system to verify that it was in accordance with 10 CFR 50.48, Operating License Condition 2.F, NRC SERs in NUREG 1038, and the UFSAR. The team conducted plant walkdowns of local manual operator actions identified in the post-fire SSD procedures to determine the adequacy of the emergency lighting units (ELUs) used to support plant personnel during post-fire SSD for the selected FAs/FZs. The team conducted walkdowns and observed the placement, alignment and coverage area of fixed 8-hour battery pack ELUs to evaluate their adequacy for illuminating access and egress pathways and any equipment requiring local operation and/or instrumentation monitoring for post-fire SSD.

The manufacturers information and vendor manuals for the installed 8-hour battery pack ELUs were reviewed to verify that the battery power supplies were rated with at least an 8-hour capacity as described in UFSAR Section 9.5.1. The team reviewed test records for the past year of periodic maintenance functional tests, as well as the annual capacity tests, to confirm that the batteries were being properly maintained and had the capacity to supply eight hours of lighting. The team reviewed the ARs that had been initiated for the identified test failures to verify that the deficiencies were evaluated, tracked, and corrected in accordance with the CAP. Additionally, the team reviewed lighting layout drawings and lighting panel details for the selected FAs/FZs to assess if the lighting circuits and sources used for the areas were diverse such that a fire in one of the areas would not affect the lighting required for SSD operations in other areas.

b. Findings

No findings of significance were identified.

.10 Cold Shutdown Repairs

a. Inspection Scope

The team reviewed the licensees SSA, FPP procedures, and conducted an electrical circuit analysis of the credited train of residual heat removal as a sample to verify the licensees assertion that for damaged equipment repairs are not relied on to achieve post-fire cold shutdown. The team examined the cable routing with respect to the selected FAs/FZs to verify that the pump would be available for post-fire SSD without any necessary repairs. Based on this review, the team confirmed that the licensees post-fire SSD procedures did not rely on cold shutdown repairs.

b. Findings

No findings of significance were identified.

.11 Compensatory Measures

a. Inspection Scope

The team reviewed the administrative controls for out-of-service, degraded, and/or inoperable fire protection features (e.g., detection and suppression systems and equipment, passive fire barriers, or pumps, valves or electrical devices providing SSD functions or capabilities). The team reviewed selected items on the fire protection impairment log and compared them with the FAs/FZs selected for inspection. The compensatory measures that had been established in these areas/zones were compared to those specified for the applicable fire protection feature to verify that the risk associated with removing the fire protection feature from service was properly assessed and adequate compensatory measures were implemented in accordance with the approved FPP. Additionally, the team reviewed the licensees short term compensatory measures (e.g., the continuous fire watch established for the degraded sprinkler system in CSRA) to verify that they were adequate to compensate for a degraded function or feature until appropriate corrective actions could be taken, and that the licensee was effective in returning the equipment to service in a reasonable period of time.

b. Findings

No findings of significance were identified.

OTHER ACTIVITIES

4OA2 Identification and Resolution of Problems

a. Inspection Scope

The team reviewed selected ARs and NCRs related to the Shearon Harris FPP to verify that items related to fire protection and SSD were appropriately entered into the licensees CAP in accordance with the licensees quality assurance program and procedural requirements. This review was conducted to assess the frequency of fire incidents and effectiveness of the fire prevention program and any maintenance-related or material condition problems related to fire incidents.

The team also reviewed other CAP documents, including completed corrective actions documented in selected ARs and NCRs, and operating experience program (OEP)documents to verify that industry-identified fire protection issues potentially or actually affecting Shearon Harris were appropriately entered into, and resolved by, the CAP process. Items included in the OEP effectiveness review were NRC regulatory issue summaries, information notices, generic letters, industry or vendor generated reports of noncompliances and defects under 10 CFR Part 21, and vendor information letters.

Additionally, the team reviewed a sample of other identified issues. The documents reviewed are listed in the Attachment.

b. Findings

No findings of significance were identified.

4OA6 Meetings, Including Exit

On October 10, 2008, the lead inspector presented the inspection results to Mr. C.

Burton, Harris Plant Vice President, and other members of the licensees staff. The licensee acknowledged the findings. Proprietary information is not included in this report. Following completion of additional reviews in the Region II office, another exit meeting was held by telephone with Mr. Burton and other members of his staff on December 18, 2008, to provide an update on changes to the preliminary inspection findings. The licensee acknowledged the findings.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee personnel

R. Atkins, Reactor Operator
C. Burton, Vice President Harris Plant
D. Corlett, Supervisor, Licensing/Regulatory Programs
M. Denny, Engineering Supervisor, Equipment Performance
J. Doorhy, Licensing Specialist, Licensing/Regulatory Programs
J. Dufner, Manager, Maintenance
R. Duncan, Vice President Nuclear Operations
J. Ertman, Supervisor, Corporate Fire Protection
K. Harshaw, Manager, Site Support Services
K. Henderson, Plant General Manager
A. Holder, Senior Engineering Technical Support Specialist, Corporate Engineering Support
G. Kilpatrick, Training Manager
J. MacIntyre, Fire Protection Engineer
L. Martin, Superintendent, Design Engineering
S. OConnor, Manager, Engineering
A. Pearson, Fire Protection Engineer
J. Pierce, Manager, Nuclear Assessment Section
B. Rhodes, Lead Engineer, Fire Protection Team
S. Saunders, Superintendent, Systems Engineering
A. Zimmerman, Licensing Specialist, Licensing/Regulatory Programs

NRC personnel

K. Korth, Acting Senior Resident Inspector
P. Lessard, Resident Inspector
R. Musser, Chief, Reactor Projects Branch 4, Division of Reactor Projects
R. Nease, Chief, Engineering Branch 2, Division of Reactor Safety
M. Pribish, Acting Senior Resident Inspector

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened/Closed

05000400/2008008-01 NCV Sprinkler System in Cable Spreading Room A Does Not Meet Licensees Fire Protection Program Requirements (Section 1R05.04)

LIST OF DOCUMENTS REVIEWED

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