ML071570599

Issuance of Emergency Amendment Regarding One-Time Extension of Emergency Diesel Generator Allowed Outage Time

ML071570599
Person / Time
Site:	McGuire
Issue date:	06/08/2007
From:	Stang J NRC/NRR/ADRO/DORL/LPLII-1
To:	Gordon Peterson Duke Power Co
Stang J, NRR/DORL, 415-1345
Shared Package
ML071590075	List: ML071570599 ML071620365
References
TAC MD5724
Download: ML071570599 (22)

Text

June 8, 2007 Mr. G. R. Peterson Vice President McGuire Nuclear Station Duke Power Company LLC 12700 Hagers Ferry Road Huntersville, NC 28078

SUBJECT:

MCGUIRE NUCLEAR STATION, UNIT 1 - ISSUANCE OF EMERGENCY AMENDMENT REGARDING ONE-TIME EXTENSION OF EMERGENCY DIESEL GENERATOR ALLOWED OUTAGE TIME (TAC NO. MD5724)

Dear Mr. Peterson:

The Commission has issued the enclosed Amendment No. 241 to Renewed Facility Operating License No. NPF-9 for the McGuire Nuclear Station, Unit 1. This amendment is in response to your application dated June 7, 2007, as supplemented June 8, 2007. This emergency amendment request was made under the provisions of Section 50.91(a)(5) to Title 10 of the Code of Federal Regulations. This amendment approves a one-time extension of the allowed outage time (AOT) for the 1A emergency diesel generator from 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to a total of 10 days.

A copy of the Safety Evaluation is also enclosed. Notice of Issuance will be included in the Commission's biweekly Federal Register notice.

Sincerely,

/RA/

John Stang, Senior Project Manager Plant Licensing Branch II-1 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket No. 50-369

Enclosures:

1. Amendment No. 241 to NPF-9

2. Safety Evaluation cc w/enclosures: See next page

June 8, 2007 Mr. G. R. Peterson Vice President McGuire Nuclear Station Duke Power Company LLC 12700 Hagers Ferry Road Huntersville, NC 28078

SUBJECT:

MCGUIRE NUCLEAR STATION, UNIT 1 - ISSUANCE OF EMERGENCY AMENDMENT REGARDING ONE-TIME EXTENSION OF EMERGENCY DIESEL GENERATOR ALLOWED OUTAGE TIME (TAC NO. MD5724)

Dear Mr. Peterson:

The Commission has issued the enclosed Amendment No. 241 to Renewed Facility Operating License No. NPF-9 for the McGuire Nuclear Station, Unit 1. This amendment is in response to your application dated June 7, 2007, as supplemented June 8, 2007. This emergency amendment request was made under the provisions of Section 50.91(a)(5) to Title 10 of the Code of Federal Regulations. This amendment approves a one-time extension of the allowed outage time (AOT) for the 1A emergency diesel generator from 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to a total of 10 days.

A copy of the Safety Evaluation is also enclosed. Notice of Issuance will be included in the Commission's biweekly Federal Register notice.

Sincerely,

/RA/

John Stang, Senior Project Manager Plant Licensing Branch II-1 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket Nos. 50-369

Enclosures:

1. Amendment No. 241 to NPF-9

2. Safety Evaluation cc w/enclosures: See next page DISTRIBUTION: Public RidsAcrsAcnwMailCenter LPL2-1 R/F GHill (4 hard copies)

RidsNrrDorlLpl2-1 (EMarinos)

RidsNrrDirsItsb (TKobetz)

RidsNrrPMJStang (hard copy)

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RidsNrrDorlDpr RidsOgcRp RidsNrrEeebMCconnell RidsNrrAplaAHowe Package No.: ML071590075 Amendment No.: ML071570599 Tech Spec No.: ML071620365

• By Memorandum dated June 8, 2007 OFFICE LPL1-2/GE LPL2-2/PM LPL2-2/LA EEEB/BC APLA/BC ITSB/BC OGC LPL2-2/BC NAME CSanders JStang MOBrien GWilson*

MRubin TKobetz DATE 06/08/07 06/08/07 06/08/07 06/08/07 06/08 /07 06/08 /07 06/08 /07

/ /07 OFFICIAL RECORD COPY

McGuire Nuclear Station, Unit 1 cc:

Vice President McGuire Nuclear Station Duke Power Company, LLC 12700 Hagers Ferry Road Huntersville, NC 28078 Associate General Counsel and Managing Attorney Duke Energy Carolinas, LLC 526 South Church Street - EC07H Charlotte, North Carolina 28202 County Manager of Mecklenburg County 720 E. Fourth St.

Charlotte, NC 28202 Regulatory Compliance Manager Duke Energy Corporation McGuire Nuclear Site 12700 Hagers Ferry Road Huntersville, NC 28078 Senior Resident Inspector U.S. Nuclear Regulatory Commission 12700 Hagers Ferry Road Huntersville, NC 28078 Mecklenburg County Department of Environmental Protection 700 N. Tryon St Charlotte, NC 28202 Vice President Customer Relations and Sales Westinghouse Electric Company 6000 Fairview Road, 12th Floor Charlotte, NC 28210 NCEM REP Program Manager 4713 Mail Service Center Raleigh, NC 27699-4713 Assistant Attorney General NC Department of Justice P.O. Box 629 Raleigh, NC 27602 Manager Nuclear Regulatory Issues &

Industry Affairs Duke Energy Corporation 526 S. Church St.

Mail Stop EC05P Charlotte, NC 28202 Division of Radiation Protection NC Dept of Environment, Health & Natural Resources 3825 Barrett Dr.

Raleigh, NC 27609-7721 Owners Group (NCEMC)

Duke Energy Corporation 4800 Concord Road York, SC 29745 Group Vice President, Nuclear Generation

& Chief Nuclear Officer P.O. Box 1006-EC07H Charlotte, NC 28201-1006 Senior Counsel Duke Energy Carolinas, LLC 526 South Church Street - EC07H Charlotte, NC 28202

DUKE POWER COMPANY LLC DOCKET NO. 50-369 MCGUIRE NUCLEAR STATION, UNIT 1 AMENDMENT TO RENEWED FACILITY OPERATING LICENSE Amendment No. 241 Renewed License No. NPF-9 1.

The Nuclear Regulatory Commission (the Commission) has found that:

A.

The application for amendment by Duke Power Company LLC (the licensee) dated June 7, 2007, as supplemented June 8, 2007, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commission's rules and regulations set forth in 10 CFR Chapter I; B.

The facility will operate in conformity with the application, the provisions of the Act, and the rules and regulations of the Commission; C.

There is reasonable assurance (i) that the activities authorized by this amendment can be conducted without endangering the health and safety of the public, and (ii) that such activities will be conducted in compliance with the Commission's regulations; D.

The issuance of this amendment will not be inimical to the common defense and security or to the health and safety of the public; and E.

The issuance of this amendment is in accordance with 10 CFR Part 51 of the Commission's regulations and all applicable requirements have been satisfied.

2.

Accordingly, the license is amended by changes to the Technical Specifications as indicated in the attachment to this license amendment and paragraph 2.C.(2) of Renewed Facility Operating License No. NPF-9 is hereby amended to read as follows:

(2)

Technical Specifications The Technical Specifications contained in Appendices A, as revised through Amendment No. 241, are hereby incorporated in the license. The licensee shall operate the facility in accordance with the Technical Specifications.

3.

This license amendment is effective as of its date of issuance and shall be implemented within 30 days from the date of issuance.

FOR THE NUCLEAR REGULATORY COMMISSION

/RA/

Evangelos C. Marinos, Chief Plant Licensing Branch II-1 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation

Attachment:

Changes to License No. NPF-9 and the Technical Specifications Date of Issuance: June 8, 2007

ATTACHMENT TO LICENSE AMENDMENT NO. 241 RENEWED FACILITY OPERATING LICENSE NO. NPF-9 DOCKET NO. 50-369 Replace the following pages of the Renewed Facility Operating Licenses and the Appendix A Technical Specifications (TSs) with the attached revised pages. The revised pages are identified by amendment number and contain marginal lines indicating the areas of change.

LICENSE PAGES LICENSE PAGES NPF-9 page 3 NPF-9 page 3 TS PAGES TS PAGES 3.8.1-3 3.8.1-3

SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION RELATED TO AMENDMENT NO. 241 TO RENEWED FACILITY OPERATING LICENSE NO. NPF-9 DUKE POWER COMPANY LLC MCGUIRE NUCLEAR STATION, UNIT 1 DOCKET NO. 50-369

1.0 INTRODUCTION

By letter dated June 7, 2007, as supplemented June 8, 2007, addressed to the Nuclear Regulatory Commission (NRC), Duke Power Company LLC (Duke, the licensee) requested changes to the Technical Specifications (TSs) for McGuire Nuclear Station, Unit 1 (McGuire 1).

The proposed amendment requests a one-time change to the allowed outage time (AOT) for the 1A emergency diesel generator (EDG) from 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to a total of 10 days. Specifically, the change would allow a one-time revision to the Unit 1 completion time for TS required action 3.8.1 from 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to a total of 10 days to support ongoing diesel generator 1A component repairs and related testing activities.

On June 5, 2007, the licensee declared 1A EDG inoperable in preparation for a scheduled performance and routine diesel generator operability surveillance tests prescribed by TS Surveillance Requirement (SR) 3.8.1. This inoperability resulted in entering the ACTION statements of TS Limiting Condition for Operability (LCO) 3.8.1.B to conduct the associated SR tests.

During the performance of the test, the control room received an overload alarm. The licensee determined the cause of the alarm to be an electrical problem with the 1A EDG jacket/intercooler water pump motor. The jacket/intercooler water pump motor is required for EDG operability. The licensee indicated that the problem was related to a random electrical failure having developed within the motor. Although the root cause is unknown at this time, the licensee regards this as an isolated problem not impacting any of the other EDGs. The licensee noted that each of the other jacket/intercooler water pump and motor were run successfully on June 6, 2007. This information has given the licensee high confidence that the remaining EDGs do not have a similar problem that was observed on EDG 1A.

Following the above failure, the 1A EDG jacket/intercooler water pump motor underwent diagnostic testing and an internal visual inspection of the motor windings. The licensee determined that the jacket/intercooler water pump motor should be sent to a vendor for repair.

No replacement motor or viable alternative cooling options that could be implemented within the timeframe of the LCO could be identified. The licensee stated that completion of repairs, post-maintenance testing, and surveillance testing to reestablish operability may not be completed prior to expiration of the 72-hour allowed outage time timeframe. Therefore, the licensee is requesting a one-time extension of this 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> allowed outage time by an additional 7 days to assure adequate time is available for completion of repairs, post-maintenance testing, and surveillance testing of the EDG.

2.0 REGULATORY EVALUATION

The following are applicable regulations and regulatory guidance used by the NRC staff in evaluating the proposed emergency license amendment:

The Commission's regulatory requirements related to the content of the TSs are set forth in Title 10 to the Code of Federal Regulations (10 CFR), Part 50, Section 50.36. This regulation requires that the TSs include items in five specific categories. These categories include 1) safety limits, limiting safety system settings and limiting control settings, 2) limiting conditions for operation, 3) surveillance requirements, 4) design features, and 5) administrative controls.

Appendix A of 10 CFR Part 50, General Design Criterion (GDC) 17, Electric power systems, requires, in part, that nuclear power plants have onsite and offsite electric power systems to permit the functioning of structures, systems, and components that are important to safety. The onsite system is required to have sufficient independence, redundancy, and testability to perform its safety functions, assuming a single failure. The offsite power system is required to be supplied by two physically independent circuits that are designed and located so as to minimize, to the extent practical, the likelihood of their simultaneous failure under operating and postulated accident and environmental conditions. In addition, this criterion requires provisions to minimize the probability of losing electric power from the remaining electric power supplies as a result of loss of power from the unit, the offsite transmission network, or the onsite electric power supplies.

Appendix A of 10 CFR Part 50, GDC 18, Inspection and testing of electric power systems, requires that electric power systems that are important to safety must be designed to permit appropriate periodic inspection and testing.

Section 50.63 of 10 CFR, Loss of all alternating current power, requires that each light-water cooled nuclear power plant licensed to operate be able to withstand for a specified duration and recover from a station blackout.

Regulatory Guide (RG) 1.174, An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis, describes a risk-informed approach that is acceptable to the NRC for assessing the nature and impact of proposed licensing-basis changes by considering engineering issues and applying risk insights.

RG 1.177, An Approach for Plant Specific, Risk-Informed Decisionmaking: Technical Specifications, describes a risk-informed approach that is acceptable to the NRC for assessing the nature and impact of proposed TS changes. RG 1.174 and 1.177 are applicable to permanent changes, and are used as guidance by the staff to evaluate this temporary change.

3.0 TECHNICAL EVALUATION

3.1. Risk Assessment Evaluation In evaluation of the risk information submitted by the licensee for proposed changes to TS 3.8.1, AC Sources - Operating," the NRC staff used the three-tiered approach and the five key principles outlined in Regulatory Guides (RGs) 1.174 and 1.177, as presented in the following sections.

3.1.1 Implementation and Monitoring Program RG 1.174 and RG 1.177 establish the need for an implementation and monitoring program to ensure that extensions to TS AOTs do not degrade operational safety over time and that no adverse degradation occurs due to unanticipated degradation or common cause mechanisms.

An implementation and monitoring program is intended to ensure that the impact of the proposed TS change continues to reflect the reliability and availability of systems, subsystems, and components (SSCs) impacted by the change. The potential impact to reliability and availability is limited by the one-time allowed extension to the AOT for this application, and no further performance measurement strategies are required.

3.1.2 Tier 1: Probabilistic Risk Assessment (PRA) Capability and Insights The first tier evaluates the impact of the proposed changes on plant operational risk. The Tier 1 NRC staff review involves two aspects: (1) evaluation of the adequacy of the McGuire 1 PRA models and their application to the proposed changes, and (2) evaluation of the PRA results and insights based on the licensees proposed application.

PRA Quality The objective of the PRA quality review is to determine whether the McGuire 1 PRA used in evaluating the proposed changes to TS 3.8.1 AOT is of sufficient scope, level of detail, and technical adequacy for this application. The NRC staff review evaluated the PRA quality information provided by the licensee in their submittal, including industry peer review results.

The McGuire 1 PRA model is a full scope PRA including both internal and external events, addressing both level 1 (core damage) and level 2 (containment performance and large early release). The original McGuire 1 PRA was a full scope level 3 PRA with internal and external events. The McGuire 1 response to GL 88-20 for an Individual Plant Examination (IPE) was provided by letter dated November 4, 1991, and included an updated McGuire 1 PRA (Revision

1) study which was the culmination of the review and update which began in January 1988. In 1997, McGuire 1 initiated Revision 2 of the 1991 IPE and provided the results to the NRC in 1998. Revision 3 of the McGuire 1 PRA was completed in July 2002 and Revision 3a was completed in February 2005. Revision 3 was a comprehensive revision to the PRA models and associated documentation. Revision 3a was a minor change to merge the Containment Air Return and Hydrogen Mitigation fault trees into the simplified large early release frequency (LERF) fault tree.

Between October 23 - 27, 2000, McGuire 1 participated in the Westinghouse Owners Group (WOG) PRA Certification Program. This review followed a process that was originally developed and used by the Boiling Water Reactor Owners Group (BWROG) and subsequently broadened to be an industry-applicable process through the Nuclear Energy Institute (NEI) Risk Applications Task Force. The resulting industry document, NEI-00-02, describes the overall PRA peer review process.

Based on the PRA peer review report, the McGuire 1 PRA received six Fact and Observations (F&O) with the significance level of "A" and 31 F&O with the significance level of "B." All six of the "A" F&O have been resolved and changes have been incorporated into McGuire 1 PRA Revision 3a, the current PRA model. The "B" F&O have been reviewed and prioritized for incorporation into the PRA. Twelve of the "B" F&O have already been incorporated into Revision 3a of the PRA. The 19 remaining "B" F&O were reviewed with respect to the impact on the PRA and were determined to be insignificant with respect to this TS change.

The licensee identified its administrative processes and procedures for updating and maintaining the McGuire 1 PRA models. In response to an RAI, the licensee identified that there were four outstanding plant changes not yet incorporated into the PRA models. One of the four, dealing with a plant change which reduced the time available for local throttling of auxiliary feedwater flow and therefore would increase the human error probability, was determined to potentially impact the analyses supporting this proposed change. Therefore, the licensee made necessary changes to the baseline PRA model. Thus the PRA models used for this application reasonably reflect the McGuire 1 facility.

The preliminary troubleshooting of the faulted 1A EDG jacket/intercooler water pump motor indicates that a random electrical failure has developed within the motor. This is further supported by the fact that each of the other jacket/intercooler water pump and motors were successfully run on June 6, 2007, following the failure of the 1A EDG jacket/intercooler water pump motor. Therefore, a potential common cause failure mode has not been identified at this time. Based on this, the licensee did not assume increased likelihood of common cause failure.

The licensee applied truncation levels consistent with their baseline PRA model for this application, identified as 1E-9 for core damage frequency (CDF) and 1E-10 for LERF. The licensee stated that it reviewed the resulting cutsets and determined that there is adequate representation of the diesel generator failure in the results so that there was no need to solve to any lower truncation levels.

Based on review of the above information, the NRC staff finds that the licensee has satisfied the intent of RG 1.177 (Sections 2.3.1, 2.3.2, and 2.3.3), RG 1.174 (Sections 2.2.3 and 2.5),

and Standard Review Plan (SRP) Chapter 19.1, and that the quality of the McGuire 1 PRA is sufficient to support the risk evaluation provided by the licensee in support of the proposed license amendment.

PRA Results and Insights The licensee provided baseline CDF and LERF, incremental conditional core damage probability (ICCDP) and incrementally conditional large early release probability (ICLERP), and CDF and LERF applicable for a one time 10 day CT for the 1A EDG. The quantitative results excluded seismic risk contributions, which are discussed qualitatively.

The licensee stated that the PRA model credits the Standby Shutdown Facility, and does not include credit for equipment repair and recovery of the DGs, or any other equipment. The licensee assumed no concurrent testing and maintenance activities, consistent with its proposed tier 2 restrictions. Since the proposed AOT extension is a one-time change, the licensee is able to administratively control discretionary maintenance and testing activities, and so it is reasonable to include this assumption in its risk analyses.

The calculation methodology is therefore reasonably consistent with the guidance of RG 1.177, Section 2.3.4 and Section 2.4 and is, therefore, acceptable to the NRC staff for evaluation of this temporary change.

The results of the licensees assessment are as follows:

Baseline CDF:

2.9E-5/year ICCDP:

1.1E-6 CDF:

1.1E-6/year Baseline LERF:

2.4E-6/year ICLERP:

1.3E-7 LERF:

1.3E-7/year The risk impacts for the proposed one-time change to TS 3.8.1 AOT from 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to a total of 10 days were found to be slightly (approximately a factor of two) above the RG 1.177 acceptance guideline of less than 5E-7 for ICCDP, and 5E-8 for ICLERP for permanent changes to the TS. The risk impacts are well below the RG 1.174 acceptance guidelines for small changes of less than 1E-5/year for CDF and 1E-6/year for LERF, with the baseline CDF and LERF less than 1E-4/year and 1E-5/year, respectively. The risk impacts are only slightly above the RG 1.174 acceptance guidelines for very small changes. The analysis assesses CDF and the LERF for the current year only when the one-time change is implemented, and there is no permanent increase in these parameters.

The licensee cited a precedent licensing action where a one-time extension to an AOT was found acceptable with risk impacts slightly exceeding the acceptance guidelines for permanent changes with additional compensatory measures applied. The document identified a specific quantitative acceptance guideline for temporary changes. The NRC staff notes that guidelines for temporary changes have not been established by any formal agency process, nor documented in applicable regulatory guidance. Therefore, the NRC staff will not apply the quantitative acceptance guideline as a precedent.

Since the proposed changes are only applicable on a one-time basis under administrative control, the NRC staff finds that the licensee has satisfied the intent of RG 1.177 (Section 2.4),

RG 1.174 (Sections 2.2.4 and 2.2.5), and SRP Chapter 19.1.

External Events The licensee stated that the McGuire 1 PRA model is a full-scope model which addresses internal fires, internal floods, and other external events excluding seimic events. The risk impact of the proposed change from these events was therefore quantitatively evaluated by the licensee and included in the risk metrics presented. The licensee stated that seismic results typically are not sensitive to unavailabilities of individual components and the seismic impact for this application is judged to be insignificant relative to the non-seismic impacts. In response to a request for additional information (RAI), the licensee identified the frequency of a seismically induced loss of offsite power (LOOP) was a small fraction of the assumed LOOP frequency used in their analyses. The frequency of exceedance for a 0.1 g event is approximately 3E-04/year. This is much smaller than both the nominal LOOP frequency of 5.1E-02/year and the tornado initiating event frequency of 7.1E-04/year. Therefore, the contribution of seismic events to the risk impact of the one-time EDG CT extension would be very small.

Based on the quantitative treatment of external events discussed above, and the qualitative disposition of seismic events, the NRC staff finds that the licensee has satisfied the intent of RG 1.177 (Section 2.3.2), RG 1.174 (Section 2.2.3), and SRP Chapter 19.1.

Shutdown and Transition Risk The licensee did not provide a quantitative assessment of shutdown or transition risk. However, the licensee identified that the proposed change would avoid transition risk of an unplanned shutdown. Since these avoided risks are not quantified, the stated risk impact of the proposed one time AOT extension is conservative.

Uncertainty As identified in RG 1.177, risk analyses of AOT extensions are relatively insensitive to uncertainties, since they affect both the base case and the changed case. In response to an RAI, the licensee stated that uncertainty issues associated with equipment repair, mean downtimes, and common cause failure, identified in RG 1.177, were not applicable to this analysis.

The licensee assessed the impact of increased loss of offsite power frequency (doubling the frequency) and increased common cause failure probability of the remaining operable diesel generator (assessed at the common cause beta-factor), and stated that with these assumptions the analyses still support the proposed one-time 1A EDG AOT extension.

Based on the above, the NRC staff finds the licensees Tier 1 evaluation of the risk impacts support the implementation of a one-time change to TS 3.8.1 to extend the AOT for one 1A inoperable diesel generator, and is acceptable to the NRC staff.

3.1.3 Tier 2 - Avoidance of Risk-Significant Plant Configurations The second tier requires a licensee to provide reasonable assurance that risk-significant plant equipment outage configurations will not occur when specific plant equipment is taken out-of-service in accordance with the proposed TS change.

The licensee identified administrative controls applicable during the extended AOT:

Currently, the A Train of control room ventilation and chilled water systems (VC/YC) is out of service for scheduled work. Once the A Train of VC/YC is returned to operable status, it will remain aligned to Unit 2 power to preclude adding further risk to the 1A Train Essential Switchgear.

The Switchyard is a controlled access area. All elective work has been suspended and will not resume until the 1A EDG has been returned to operable status.

As a further enhancement to the communications protocols implemented as part of Generic Letter (GL) 2006-02 response, daily communications will take place between McGuire 1 Operations and the Grid Operator.

Routine essential equipment rotations during the duration of the extension on both units will not occur as scheduled due to the problem with the 1A EDG. This action will prevent any challenges to the offsite power source to 1ETA by not placing additional loads on the normal incoming breaker. Maintenance and testing during the allowed outage time extension will be rescheduled for both Units as warranted minimizing the risk of Unit transients.

In addition, the following equipment will be protected by plant procedure:

4160 Essential Bus (1ETA) 1A/2A Busline 6900/4160 Auxiliary Transformer (1ATC) 6900/4160 Auxiliary Transformer (SATA) 4160 Essential Bus (1ETB) 1B/2B Busline 6900/4160 Auxiliary Transformer (1ATD) 6900/4160 Auxiliary Transformer (SATB)

Unit 1 Transformer Yard Unit 2 Transformer Yard Switchyard Standby Shutdown Facility (SSF)

Unit 1 Auxiliary Feedwater (CA) Pumps Unit 1 Nuclear Service Water (RN) Pumps 1B Chemical & Volume Control (NV) Pump 1B Residual Heat Removal (ND) Pump 1B Safety Injection (NI) Pump 1B Containment Spray (NS) Pump Unit 1 Component Cooling (KC) Pumps B Train Control Area HVAC/Chilled Water (VC/YC) 1B Emergency Diesel Generator (EDG)

Instrument Air Compressors (VI)

To minimize the risk of losing offsite power to the 1A 4.16 kV Essential Bus, surveillances will not be performed for the 1A undervoltage and degraded voltage relaying. As a result, the TS Surveillance for 3.3.5, "Loss of Power EDG Start Instrumentation," will expire during this period of 1A EDG unavailability. This surveillance will be performed once 1A EDG is returned to an available status.

Based on the above, the NRC staff finds the licensees tier 2 evaluation of potential risk significant configurations and the proposed tier 2 restrictions support the implementation of a one-time change to TS 3.8.1 to extend the AOT for one inoperable diesel generator, and is acceptable to the NRC staff.

3.1.4 Tier 3 - Risk-Informed Configuration Risk Management The third tier requires a licensee to develop a program that ensures that the risk impact of out-of-service equipment is appropriately evaluated prior to performing any maintenance activity.

The licensee identified 10 CFR 50.65(a)(4), RG 1.182, and NUMARC 93-01 require that prior to performing maintenance activities, risk assessments shall be performed to assess and manage the increase in risk that may result from proposed maintenance activities. The licensee stated that it has approved procedures and directives in place at McGuire 1 to ensure the requirements of the Maintenance Rule are implemented.

The NRC staff finds the licensees tier 3 program is acceptable and supports the proposed one-time change to TS 3.8.1 to extend the AOT for the 1A inoperable diesel generator, and is acceptable to the NRC staff.

3.1.5 Comparison With Regulatory Guidance The acceptance guidelines of RG 1.174 and RG 1.177 are applicable to permanent changes to the plant licensing basis. The acceptance guidelines of RG 1.174 for CDF and LERF for small changes in risk are met for this temporary change. The acceptance guidelines of RG 1.177 for ICCDP and ICLERP are exceeded, but do not consider quantitatively the avoided transition and shutdown risk.

3.1.6 NRC staff Findings and Conditions The tier 1 risk impacts for the proposed one-time change to TS 3.8.1 AOT to extend the AOT for the 1A EDG is within the RG 1.174 acceptance guidelines for CDF and LERF for small changes, and slightly exceed the RG 1.177 acceptance guidelines for ICCDP and ICLERP.

These acceptance guidelines are applicable for permanent changes to the plant licensing basis, and the risk impact of this temporary change is considered to be small and consistent with the intent of the Commissions Safety Goal Policy Statement. The tier 2 analysis provides reasonable assurance that risk-significant plant equipment outage configurations will not occur when specific plant equipment is taken out of service in accordance with the proposed TS change. The licensees tier 3 CRMP is consistent with the RG 1.177 CRMP guidelines. The proposed change to TS 3.8.1 to extend the AOT for the 1A EDG satisfies the fourth key principle of risk-informed decisionmaking identified in RG 1.174 and RG 1.177 and is therefore acceptable within the NRC review scope for implementing risk-informed decisionmaking.

3.2 Deterministic Evaluation The McGuire onsite electrical power system consists of all sources of electrical power and their associated distribution systems in each of the two generating units. These sources are the main generator, two EDGs and the batteries. Each McGuire unit has two redundant and independent 4160 Volt (V) Essential Auxiliary Power Systems which normally receive power for the normal power distribution system. After verification of a loss of offsite power (LOOP) or a sustained degraded offsite power condition, the normal and alternate incoming feeder circuit breakers automatically trip. During a LOOP condition, power to each of the redundant 4160 V Essential Auxiliary Power Systems is provided by a completely independent diesel-electric generating unit. Each of the 4160 V Essential Auxiliary Power System (1E) electrical buses is totally capable of fulfilling their design function independently. There are no overlapping electrical loads shared between the McGuire 1E buses. Furthermore, a loss of one EDG does not increase the demand on any other EDG.

The operability requirements for the McGuire, Unit 1, AC sources during plant operation ensures that sufficient power will be available to supply safety-related equipment required for

1) the safe shutdown of the facility, and 2) the mitigation and control of accident conditions within the facility. The minimum specified independent and redundant alternating power sources satisfy the requirements of GDC 17.

The TS Action requirements specified for the levels of degradation of the power sources provide restrictions for continued facility operation commensurate with the level of degradation.

The operability requirements for the power sources are consistent with the initial condition assumptions of the accident analyses and are based upon maintaining the remaining AC power sources and associated distribution systems operable.

According to Regulatory Guide 1.93, operation may continue with one EDG inoperable for a period that should not exceed 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. In this condition, the remaining operable EDG and offsite circuits are adequate to supply electrical power to the onsite safety-related electrical distribution system. This 72-hour period takes into account the capability and capacity of the remaining AC sources, a reasonable time for repairs, and the low probability of a design basis accident during this period.

McGuire, Unit 1, TS 3.8.1 currently requires that two separate and independent EDGs, capable of supplying the Onsite Essential Auxiliary Power Systems, be operable in Modes 1, 2, 3, and 4.

With one EDG inoperable, TS 3.8.1 Condition B, Required Action B.4 requires the restoration of the inoperable EDG to an operable status within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or the Unit must be in at least hot standby (Mode 3) within the next 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> and in cold shutdown (Mode 5) within the following 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br />.

During routine surveillance of the 1A EDG, the McGuire, Unit 1, Control Room received a non-tripping computer alarm (approximately 23 minutes after the 1A EDG was shutdown) indicating an administrative current overload condition on the 1A EDG KD Jacket Water Cooling Pump Motor, simultaneous with the motor stopping. The licensee did not note any problems with the 1A EDG KD Jacket Water Cooling Pump Motor during the EDG run. Following the event, the licensee attempted to troubleshoot the motor by performing several electrical tests including a Megger, winding resistance, and Polarization Index test. The licensee stated that the results of the tests indicated no problems with the motor. The licensee then performed a stepped direct current (DC) voltage Hi-Pot and Surge test of the motor. The licensee reported that both tests gave repeatable data and indicated a potential problem with the windings. The licensee subsequently removed the 1A EDG KD Jacket Water Cooling Pump Motor and sent it to an offsite vendor (Shultz Electric) for inspection and attempted repair.

The vendor disassembled the motor and discovered an apparent hard rub between the stator and rotor. The vendor also identified numerous pieces of metal particles inside the end-bell and in the end turn windings of the stator. Since an apparent rub was in several places around the circumference of the stator winding, the licensees initial cause investigation (based on vendor supplied information) suggested a bearing failure. However, this was later refuted as discussed below.

The licensee stated that a rub would explain why the overload alarm was received. Since the McGuire, Unit 1, computer overload alarm device is sized one standard size smaller than the expected full load current, the licensee stated that any drag or rub would cause additional current. This additional current would cause the overload alarm to be picked up as it did. The licensee further stated that if the motor had continued to run with a degrading rub, then the three phase overload, set at 150% of full load current, would have tripped the motor.

Since the 1A EDG KD Jacket Water Cooling Pump Motor was not run after the initial indication of an overload condition, the licensee has insufficient data (e.g., vibration, bearing temperatures, running amps, alignment verification) available to determine the actual cause.

However, after motor disassembly and preliminary visual inspection of the bearings the licensee did not identify any apparent bearing problems such as cage failures or looseness.

The licensee stated that their records indicate that the motor had been lubricated on May 30, 2007, and previous quarterly vibration readings associated with diesel testing, performed on May 8, 2007, were also reviewed and found to be within tolerance. The licensee further stated that the apparent rub was actually aluminum that flowed out of the rotor due to heat, that smeared onto the stator. Given that the bearings did not indicate degraded condition, the licensee concluded that the rotor did not come into contact with the stator. Upon further investigation, the licensee identified aluminum particles within the motor. Any aluminum imbedded in the windings or the slot could provide a tracking path to ground, resulting in the licensees degraded indications from the DC HI-POT test and surge test that was performed by the licensee. The degraded core due to the melted aluminum would lead to higher current draw, causing the overload alarm that was received, and would be expected for this condition.

The licensee initiated a common cause analysis following the failure of the 1A EDG KD Jacket Water Pump Motor. After reviewing historical data for the KD Jacket Water Pump Motors (e.g, degrading vibration trends or high amplitudes, and changing electrical test results), the licensee did not identify any issues. Furthermore, following the failure of the 1A EDG KD Jacket Water Pump Motor the licensee tested the remaining three KD Jacket Water Pump motors to verify operability. Each of the remaining KD Jacket Water Pump motors started and ran successfully.

These tests were completed with process fluid temperatures less than would be present with an operating EDG, which resulted in the motors running at a higher, more conservative, operating current. The licensee did not receive any overload alarms during the tests. In addition, the 2A and 2B KD Jacket Water Pump motors have significantly different model numbers, rated load speed, and full load current, as compared to the other motors. Therefore, based on the available testing, successful previous quarterly diesel testing and differences in design ratings, the NRC staff considers the remaining KD Jacket Water Pump motors to be fully operable.

With respect to grid reliability, the licensee has notified the McGuire, Unit 1, System Operating Center/Transmission Control Center (grid operator) to put actions in place to limit work activities that could affect the McGuire Switchyard for the duration of the 1A EDG repairs. This includes work activities outside the McGuire Switchyard. In actions taken in response to Generic Letter 2006-02, "Grid Reliability and the Impact on Plant Risk and the Operability of Offsite Power,"

the licensee has established protocols with the System Operating Center/Transmission Control Center to improve communications between grid operators and McGuire operating staff.

Furthermore, adverse weather procedures are in place for meteorological conditions which could potentially affect offsite power availability.

With regard to operation and maintenance restrictions for the duration of the extension, the licensee stated that the A Train of control room ventilation and chilled water system (VC/YC) is out of service for scheduled work. Once the A Train of VC/YC is returned to operable status, it will remain aligned to McGuire, Unit 2, power to preclude adding further risk to the 1A Train Essential Switchgear.

The licensee has suspended all elective switchyard work and will not resume until the 1A EDG has been returned to operable status. As a further enhancement to the communications protocols implemented as part of the licensees response to GL 2006-02, daily communications will take place between McGuire Operations and the Grid Operator.

The licensee further stated that routine essential equipment rotations during the duration of the extension on both units will not occur as scheduled due to the problem with the 1A EDG. This action will prevent any challenges to the offsite power source by not placing additional loads on the normal incoming breaker. Furthermore, elective maintenance and testing during the allowed outage time extension will be rescheduled for both Units as warranted minimizing the risk of Unit transients.

Based on the above evaluation, the NRC staff finds that the proposed revision to the McGuire 1 TSs will continue to ensure the availability of the required AC power to shut down the reactor and to maintain the reactor in a safe condition after an anticipated operational occurrence or a postulated design-basis accident. The NRC staff also concludes that the proposed TS change does not affect McGuire 1's compliance with the requirements of GDC 17 and 18. The NRC staffs conclusion is also based on the regulatory commitments provided in Section 5.0 of this safety evaluation. Therefore, the NRC staff finds the proposed change acceptable.

4.0 EMERGENCY CIRCUMSTANCES The NRCs regulations 10 CFR 50.91 contain provisions for issuance of an amendment where the Commission finds that emergency circumstances exist, in that a licensee and the Commission must act quickly and that time does not permit the Commission to publish a Federal Register notice allowing 30 days for prior public comment.

In the June 7, 2007 application, the licensee requested that this amendment be treated as an emergency amendment. In accordance with 10 CFR 50.91(a)(5), the licensee provided information regarding why this emergency situation occurred and how it could not be avoided.

The licensee provided the following explanation.

[1]

Reason Emergency Situation Has Occurred:

On June 5, 2007, at 1741 hours0.0202 days <br />0.484 hours <br />0.00288 weeks <br />6.624505e-4 months <br />, the Unit 1A EDG was declared inoperable and the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> action statement of Technical Specification (TS) 3.8.1 Required Action B was entered to perform routine TS surveillance testing. During this testing, the Control Room received an overload alarm. Subsequent troubleshooting determined the cause of the alarm to be an electrical problem with the 1A EDG Jacket/Intercooler Water Pump Motor. The motor failure was evaluated and a determination was made that the motor should be sent to a repair facility. The repair will be beyond the LCO criteria in TS 3.8.1. The Jacket/Intercooler Water Pump Motor is required for EDG operability.

[2]

Reason the Situation Could Not Have Been Avoided:

The 1A EDG jacket/Intercooler Water Pump Motor is a unique design with a shaft extending through the motor that turns a pump on each end. The preventive maintenance program for these motors is based upon EPRI Guideline TR-106857-V8, Low Voltage Electrical Motors (600 volt and below) as well as benchmarking of motor maintenance programs at other utilities. These motors receive maintenance [lubrication, external visual inspection, electrical testing (winding resistance, insulation resistance, polarization index), vibration tests, and thermographic checks] on a periodic basis in accordance with our maintenance program. In addition, the review of the 1A motor electrical test data over a 7 year period shows stable data and no degrading trends. Therefore, this failure could not have been foreseen.

The 1A EDG Jacket/Intercooler Water Pump Motor ran normally throughout the period. The failure occurred during TS required testing of the EDG.

Following the normal troubleshooting protocol, additional tests were performed indicating a problem with the electrical motor.

Further diagnostic testing and an internal visual inspection of the motor windings at the vendors facility will serve to identify the specific cause of the problem with the motor.

The Jacket/Intercooler Water Pump Motor is required for EDG operability.

Completion Times for the applicable TS 3.8.1 Required Actions expire on June 8, 2007 at 1741 hours0.0202 days <br />0.484 hours <br />0.00288 weeks <br />6.624505e-4 months <br />. A spare motor has not been located at this time and no viable alternative cooling options that could be implemented within the timeframe of this extension have been identified; therefore, the 1A EDG will not be restored to an operable status by 1741 hours0.0202 days <br />0.484 hours <br />0.00288 weeks <br />6.624505e-4 months <br /> on June 8, 2007. Alternative cooling options evaluated included:

Replacement of the single motor with two motors, one for each

pump, Mounting two motors offset from the pump centerline and coupled to the pumps through belts and pulleys, Connecting an external source of water into the system, Locating a non-safety related motor with a similar configuration, and Installing one motor to drive the pump and installation of a section of pipe in place of the intercooler pump.

The failed motor will have to be shipped to the motor repair vendor for repair and it will take more than the 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> allowed by TS 3.8.1. Neither a routine nor an exigent amendment request could have been processed with the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> period.

Therefore, an emergency amendment is needed to preclude an unnecessary shutdown.

Based on the above, the Commission finds that an emergency situation exists, in that failure to act in a timely way would result in shutdown of the plant. The licensee has explained why the emergency situation occurred and why it could not be avoided. Accordingly, the Commission has determined that emergency circumstances exist pursuant to 10 CFR 50.91(a)(5) and could not have been avoided, that the submittal of information by the licensee was timely, and the licensee did not create the emergency condition. Therefore, this request was handled under the provisions of 10 CFR 50.91(a)(5).

5.0 REGULATORY COMMITMENTS In the June 7, 2007, submittal the licensee made the following regulatory commitments for the duration of the AOT extension:

[1]

Once the A Train of the Control Room Ventilation and Chilled Water systems (VC/YC) is returned to operable status, it will remain aligned to Unit 2 power to preclude adding further risk to the 1A Train Essential Switchgear.

[2]

The Switchyard is a controlled access area. All elective work has been suspended and will not resume until the 1A EDG has been returned to operable status.

[3]

As a further enhancement to the communications protocols implemented as part of GL 2006-02 response, during the duration of the extension, daily communications will take place between McGuire Operations and the Grid Operator.

[4]

Routine essential equipment rotations during the duration of the extension on both units will not occur as scheduled due to the problem with the 1A EDG. This action will prevent any challenges to the offsite power source to 1ETA by not placing additional loads on the normal incoming breaker. Elective maintenance and testing during the allowed outage time extension will be rescheduled for both Units as warranted minimizing the risk of Unit transients..

[5]

The following equipment will be protected: 1ETA, 1ETB, 1A/2A Busline, 1B/2B Busline, 1ATC, 1ATD, SATA, SATB, U1 Transformer Yard, U2 Transformer Yard, Switchyard, Standby Shutdown Facility, U1 CA Pumps, Unit 1 RN Pumps, 1B NV Pump, 1B ND Pump, 1B NI Pump, 1B NS Pump, Unit 1 KC Pumps, B Train VC/YC, 1B EDG, and VI Compressors.

[6]

To minimize the risk of losing offsite power to the 1A 4.16 kV Essential Bus Technical Specification Surveillances for 3.3.5.1 will not be performed for the 1A undervoltage and degraded voltage relaying.As a result, the TS Surveillance for 3.3.5 Loss of Power EDG Start Instrumentation will expire during this period of 1a EDG unavailability.

This surveillance will be performed once 1A EDG is returned to an available status.

The above regulatory commitments have been entered in the licensees commitment management system which complies with Nuclear Energy Institute Document 99-04, Revision 0, Guidelines for Managing NRC Commitment Changes. The NRC staff has reviewed the regulatory commitments and how they will be controlled and finds that the licensees commitments provide adequate assurance that safe plant operation will not be affected by the extended AOT.

6.0 FINAL NO SIGNIFICANT HAZARDS CONSIDERATION

DETERMINATION The Commission's regulations in 10 CFR 50.92(c) state that the Commission may make a final determination that a license amendment involves no significant hazards consideration if operation of the facility in accordance with the amendment would not:

(1)

Involve a significant increase in the probability or consequences of an accident previously evaluated; or, (2)

Create the possibility of a new or different kind of accident from any previously evaluated; or, (3)

Involve a significant reduction in a margin of safety.

The following analysis was provided by the licensee in their letter of June 7, 2007.

A.

Does the proposed amendment involve a significant increase in the probability or consequences of an accident previously evaluated?

Response: No.

The 1A EDG functions as an accident mitigator and is not required unless an accident occurs. The 1A EDG does not affect any accident initiators or precursors. The proposed extension of the allowed outage time (AOT) does not affect the 1A EDGs interaction with any system whose failure or malfunction could initiate an accident. Therefore, the probability of an accident previously evaluated is not significantly increased.

The 1A EDG functions to mitigate a loss of offsite power to vital components.

The risk evaluation performed in support of this amendment request demonstrates that the consequences of an accident are not significantly increased. As such, the proposed change do[es] not involve a significant increase in the probability or consequences of an accident previously evaluated.

B.

Does the proposed amendment create the possibility of a new or different kind of accident from any accident previously evaluated?

Response: No.

The proposed amendment does not involve the addition, removal or modification of any plant system, structure or component. The proposed change will not affect the operation of any plant system, structure or component as directed in plant procedures. Operation of the facility in accordance with this amendment does not create the possibility of a new or different kind of accident from those previously evaluated.

C.

Does the proposed amendment involve a significant reduction in the margin of safety?

Response: No.

Based upon the availability of redundant systems, the mitigating actions that have been taken and the low probability of an accident, McGuire concludes that the reduction in availability of the 1A EDG does not result in a significant reduction in the margin of safety.

The margin of safety is related to the confidence in the ability of the fission product barriers to perform their design functions during and following an accident situation. These barriers include the fuel cladding, the reactor coolant system, and the containment system. The performance of the fuel cladding, containment and the reactor coolant system will not be significantly impacted by the proposed change.

Thus, it can be concluded that the proposed change does not involve a significant reduction in the margin of safety.

The NRC staff agrees with the licensees analysis and, based on this review has concluded that the three standards of 10 CFR 50.92(c) are satisfied. Therefore, the NRC staff makes a final determination that the amendment does not involve a significant hazards consideration.

The supplement dated June 8, 2007, provided additional information that clarified the application, and did not expand the scope of the proposed no significant hazards consideration determination.

7.0 STATE CONSULTATION

In accordance with the Commission's regulations, the North Carolina State official was notified of the proposed issuance of the amendment. The State official had no comments.

8.0 ENVIRONMENTAL CONSIDERATION

The amendment changes a requirement with respect to installation or use of a facility component located within the restricted area as defined in 10 CFR Part 20. The NRC staff has determined that the amendment involves no significant increase in the amounts, and no significant change in the types, of any effluents that may be released offsite, and that there is no significant increase in individual or cumulative occupational radiation exposure. The Commission has made a final no significant hazards finding with respect to this amendment.

Accordingly, the amendment meets the eligibility criteria for categorical exclusion set forth in 10 CFR 51.22(c)(9). Pursuant to 10 CFR 51.22(b) no environmental impact statement or environmental assessment need be prepared in connection with the issuance of the amendment.

9.0 CONCLUSION

The Commission has concluded, based on the discussion provided above that (1) the amendment does not: (a) involve a significant increase in the probability or consequences of an accident previously evaluated; or, (b) create the possibility of a new or different kind of accident from any previously evaluated; or, (c) involve a significant reduction in a margin of safety and therefore, the amendment does not involve a significant hazards consideration; (2) there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, (3) such activities will be conducted in compliance with the Commission's regulations, and (4) the issuance of the amendment will not be inimical to the common defense and security or to the health and safety of the public.

Principal Contributors: M. McConnell A. Howe Date: June 8, 2007