ML061160181

License Amendment, TS Change to Extend Completion Time for Nuclear System Protection System Inverters

ML061160181
Person / Time
Site:	Clinton
Issue date:	05/26/2006
From:	Jabbour K Plant Licensing Branch III-2
To:	Crane C AmerGen Energy Co
Jabbour K, NRR/DLPM, 415-1496
Shared Package
ML061160210	List: ML061160181 ML061500252
References
TAC MC3035
Download: ML061160181 (28)

Text

May 26, 2006 Mr. Christopher M. Crane, President and Chief Executive Officer AmerGen Energy Company, LLC 4300 Winfield Road Warrenville, Illinois 60555

SUBJECT:

CLINTON POWER STATION, UNIT 1 - ISSUANCE OF AMENDMENT -

RE: TECHNICAL SPECIFICATION CHANGE TO EXTEND COMPLETION TIME FOR NUCLEAR SYSTEM PROTECTION SYSTEM INVERTERS (TAC NO. MC3035)

Dear Mr. Crane:

The Nuclear Regulatory Commission (Commission) has issued the enclosed Amendment No. 174 to Facility Operating License No. NPF-62 for the Clinton Power Station, Unit 1. The amendment is in response to your application dated April 26, 2004, as supplemented April 18 and October 11, 2005, and May 19, 2006.

The amendment revises Technical Specification 3.8.7, "Inverters - Operating" to revise the Completion Time for restoration of an inoperable Division 1 or 2 inverter from the current 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to 7 days.

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

Sincerely,

/RA/

Kahtan N. Jabbour, Senior Project Manager Plant Licensing Branch III-2 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket No. 50-461

Enclosures:

1. Amendment No. 174 to NPF-62

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

May 26, 2006 Mr. Christopher M. Crane, President and Chief Executive Officer AmerGen Energy Company, LLC 4300 Winfield Road Warrenville, Illinois 60555

SUBJECT:

CLINTON POWER STATION, UNIT 1 - ISSUANCE OF AMENDMENT -

RE: TECHNICAL SPECIFICATION CHANGE TO EXTEND COMPLETION TIME FOR NUCLEAR SYSTEM PROTECTION SYSTEM INVERTERS (TAC NO. MC3035)

Dear Mr. Crane:

The Nuclear Regulatory Commission (Commission) has issued the enclosed Amendment No. 174 to Facility Operating License No. NPF-62 for the Clinton Power Station, Unit 1. The amendment is in response to your application dated April 26, 2004, as supplemented April 18 and October 11, 2005, and May 19, 2006.

The amendment revises Technical Specification 3.8.7, "Inverters - Operating" to revise the Completion Time for restoration of an inoperable Division 1 or 2 inverter from the current 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to 7 days.

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

Sincerely,

/RA/

Kahtan N. Jabbour, Senior Project Manager Plant Licensing Branch III-2 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket No. 50-461

Enclosures:

1. Amendment No. 174 to NPF-62

2. Safety Evaluation cc w/encls: See next page DISTRIBUTION:

PUBLIC LPL3-2 R/F GHill (2)

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• • comments only OFFICE LPL3-2/PM LPL3-2/PE LPL3-2/LA DRA/APLA/BC

• NAME KJabbour TWengert DClarke**

MRubin DATE 5/25/06 5/25/06 5/25/06 1/5/06 OFFICE EEEB/BC*

ITSB/BC OGC LPL3-2/BC NAME RJenkins TBoyce MLemoncelli DCollins DATE 5/17/05 4/12/06 4/10/06 5/25/06 OFFICIAL RECORD COPY

Clinton Power Station, Unit 1 cc:

Senior Vice President of Operations AmerGen Energy Company, LLC 4300 Winfield Road Warrenville, IL 60555 Illinois Emergency Management Agency Division of Disaster Assistance &

Preparedness 110 East Adams Street Springfield, IL 62701-1109 Vice President - Licensing and Regulatory Affairs AmerGen Energy Company, LLC 4300 Winfield Road Warrenville, IL 60555 Manager Licensing - Dresden, Quad Cities, and Clinton AmerGen Energy Company, LLC 4300 Winfield Road Warrenville, IL 60555 Regulatory Assurance Manager - Clinton AmerGen Energy Company, LLC Clinton Power Station RR3, Box 228 Clinton, IL 61727-9351 Director - Licensing and Regulatory Affairs AmerGen Energy Company, LLC 4300 Winfield Road Warrenville, IL 60555 Document Control Desk - Licensing AmerGen Energy Company, LLC 4300 Winfield Road Warrenville, IL 60555 Site Vice President - Clinton Power Station AmerGen Energy Company, LLC Clinton Power Station RR 3, Box 228 Clinton, IL 61727-9351 Clinton Power Station Plant Manager AmerGen Energy Company, LLC Clinton Power Station RR 3, Box 228 Clinton, IL 61727-9351 Resident Inspector U.S. Nuclear Regulatory Commission RR #3, Box 229A Clinton, IL 61727 Regional Administrator, Region III U.S. Nuclear Regulatory Commission Suite 210 2443 Warrenville Road Lisle, IL 60532-4351 Assistant General Counsel Exelon Generation Company, LLC 200 Exelon Way Kennett Square, PA 19348 R. T. Hill Licensing Services Manager General Electric Company 175 Curtner Avenue, M/C 481 San Jose, CA 95125 Chairman of DeWitt County c/o County Clerks Office DeWitt County Courthouse Clinton, IL 61727 J. W. Blattner Project Manager Sargent & Lundy Engineers 55 East Monroe Street Chicago, IL 60603

AMERGEN ENERGY COMPANY, LLC DOCKET NO. 50-461 CLINTON POWER STATION, UNIT 1 AMENDMENT TO FACILITY OPERATING LICENSE Amendment No. 174 License No. NPF-62 1.

The U.S. Nuclear Regulatory Commission (the Commission) has found that:

A.

The application for amendment by AmerGen Energy Company, LLC (the licensee), dated April 26, 2004, as supplemented by letters dated April 18 and October 11, 2005, and May 19, 2006, 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 Facility Operating License No. NPF-62 is hereby amended to read as follows:

(2)

Technical Specifications and Environmental Protection Plan The Technical Specifications contained in Appendix A and the Environmental Protection Plan contained in Appendix B, as revised through Amendment No. 174 are hereby incorporated into this license. The licensee shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan.

3.

This license amendment is effective as of its date of issuance and shall be implemented within 60 days of the date of issuance.

FOR THE NUCLEAR REGULATORY COMMISSION

/RA/

Daniel S. Collins, Chief Plant Licensing Branch III-2 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation

Attachment:

Changes to the Technical Specifications Date of Issuance: May 26, 2006

ATTACHMENT TO LICENSE AMENDMENT NO. 174 FACILITY OPERATING LICENSE NO. NPF-62 DOCKET NO. 50-461 Replace the following page of the Facility Operating License and Appendix "A" Technical Specifications with the attached revised pages. The revised pages are identified by an amendment number and contain a marginal lines indicating the areas of change.

Remove Page Insert Page License Page 3 License Page 3 3.8-34 3.8-34 (4)

AmerGen Energy Company, LLC, pursuant to the Act and to 10 CFR Parts 30, 40, and 70, to receive, possess, and use at any time any byproduct, source and special nuclear material as sealed neutron sources for reactor startup, sealed sources for reactor instrumentation and radiation monitoring equipment calibration, and as fission detectors in amounts as required; (5)

AmerGen Energy Company, LLC, pursuant to the Act and 10 CFR Parts 30, 40, and 70, to receive, possess, and use in amounts as required any byproduct, source or special nuclear material without restriction to chemical or physical form, for sample analysis or instrument calibration or associated with radioactive apparatus or components; and (6)

AmerGen Energy Company, LLC, pursuant to the Act and 10 CFR Parts 30, 40, and 70, to possess, but not separate, such byproduct and special nuclear materials as may be produced by the operation of the facility.

C.

This licence shall be deemed to contain and is subject to the conditions specified in the Commissions regulations set forth in 10 CFR Chapter I and is subject to all applicable provisions of the Act and to the rules, regulations and orders of the Commission now or hereafter in effect; and is subject to the additional conditions specified or incorporated below:

(1)

Maximum Power Level AmerGen Energy Company, LLC is authorized to operate the facility at reactor core power levels not in excess of 3473 megawatts thermal (100 percent rated power) in accordance with the conditions specified herein.

(2)

Technical Specifications and Environmental Protection Plan The Technical Specifications contained in Appendix A and the Environmental Protection Plan contained in Appendix B, as revised through Amendment No. 174, are hereby incorporated into this license.

AmerGen Energy Company, LLC shall operate the facility in accordance with the Technical Specifications and the Environmental Protection Plan.

Amendment No. 174

SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION RELATED TO AMENDMENT NO. 174 TO FACILITY OPERATING LICENSE NO. NPF-62 AMERGEN ENERGY COMPANY, LLC CLINTON POWER STATION, UNIT 1 DOCKET NO. 50-461

1.0 INTRODUCTION

By application dated April 26, 2004, as supplemented by letters dated April 18 and October 11, 2005, and May 19, 2006, AmerGen Energy Company, LLC (the licensee), requested a change to the Clinton Power Station (CPS) Technical Specification (TS) 3.8.7, Inverters-Operating.

The change will revise the Completion Time (CT) for Required Action A.1 regarding inoperable Division 1 or 2 nuclear system protection system (NSPS) inverters from the current 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to 7 days. The supplements dated April 18 and October 11, 2005, and May 19, 2006, provided additional information that clarified the application, but did not expand the scope of the application as originally noticed, and did not change the staffs original proposed no significant hazards consideration determination as published in the Federal Register on June 8, 2004 (69 FR 32072).

The licensees proposal also includes new regulatory commitments that are presented in Section 3.3 of this safety evaluation (SE).

1.1 Background

The NSPS inverters are the preferred source of power for the uninterruptible 120 volts alternating current (VAC) buses because of their stability and reliability. There is one NSPS inverter per uninterruptible alternating current (AC) bus, making a total of four divisional NSPS inverters. The function of the inverter is to provide AC electrical power to these buses.

The four safety-related 120 VAC inverter buses support the NSPS instrumentation. The inverters provide an uninterruptible power source for the instrumentation and controls of the reactor protection system (RPS) and the emergency core cooling system (ECCS) initiation, and miscellaneous isolations. Each NSPS bus has its own inverter supplied from a separate and independent, divisional direct current (DC) bus. There is an alternate supply to each of these NSPS buses from a safety-related 480 VAC bus. Each inverter contains a solid-state transfer switch to select the NSPS bus supply. The DC bus is the normal supply through the inverter.

However, the solid state transfer switch will shift to the alternate AC source automatically if the inverter detects abnormal conditions. The inverter also contains a manual bypass switch to the alternate AC source. As stated by the licensee, inverter failures are defined as the inverter detecting abnormal conditions and transferring to its alternate power source. The inverters automatically switch to the alternate power source for internal inverter problems and for handling fault clearing and inrush current demands. The TS Bases state that, with a required inverter inoperable, its associated uninterruptible AC bus is inoperable if not energized.

With an inverter inoperable, a loss of offsite power (LOOP) with the instrument bus being supplied from the alternate source will result in loss of power to the associated instrument bus.

Power would be restored once the associated diesel generator (DG) re-energized the bus. The licensee stated that there is no adverse impact on the plant since no instrumentation in the opposite train would be expected to be inoperable or in trip except for routine surveillance, as limited by licensee commitments identified in Section 3.3 of this SE.

The inverters are required to be operable in modes 1, 2, and 3. The inverters ensure the reliability of the AC electrical power for instrumentation required to shut down the reactor and maintain it in a safe condition after anticipated operational occurrences (AOOs) or postulated design basis accidents (DBAs).

2.0 REGULATORY EVALUATION

2.1 Applicable Regulations According to General Design Criterion (GDC) 17, Electric power systems, in Appendix A to Title 10 of the Code of Federal Regulations (10 CFR), Part 50, Domestic Licensing of Production and Utilization Facilities, nuclear power plants must have onsite and offsite electric power systems to permit the functioning of structures, systems, and components (SSCs) that are important to safety. The onsite system must have sufficient independence, redundancy, and testability to perform its safety function, assuming a single failure. The offsite power system must 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 a loss of power from the unit, the offsite transmission network, or the onsite power supplies.

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 50.36(c)(3), Surveillance requirements, states that Surveillance requirements are requirements relating to test, calibration, or inspection to assure that the necessary quality of systems and components is maintained, that facility operation will be within its safety limits, and that the limiting conditions for operation will be met.

In accordance with 10 CFR 50.65, Requirements for monitoring the effectiveness of maintenance at nuclear power plants, preventive maintenance activities must be sufficient to provide reasonable assurance that SSCs are capable of fulfilling their intended functions.

As required in 10 CFR 50.63, Loss of all alternating current power, all nuclear power plants must be able to withstand a loss of all AC power for an established period of time and recover from a station blackout (see RG 1.155, Station Blackout, dated August 1988).

As it relates to the proposed Division 1 and 2 NSPS inverter configuration, 10 CFR 50.65(a)(4) requires the assessment and management of the increase in risk that may result from the proposed maintenance activity.

The paragraph under 10 CFR 50.90, Application for amendment of license or construction permit, addresses the requirements for a licensee desiring to amend its license, which include the TSs.

2.2 Applicable Regulatory Criteria/Guidelines General guidance for evaluating the technical basis for proposed risk-informed changes is provided in Chapter 19.0, Use of Probabilistic Risk Assessment (PRA) in Plant-Specific, Risk-Informed Decisionmaking: General Guidance, of the NRC Standard Review Plan (SRP),

NUREG-0800. More specific guidance related to risk-informed TS changes is provided in SRP Section 16.1, Risk-Informed Decisionmaking: Technical Specifications, which includes CT changes as part of risk-informed decisionmaking. Chapter 19.0 of the SRP states that a risk-informed application should be evaluated to ensure that the proposed changes meet the following key principles:

The proposed change meets the current regulations, unless it explicitly relates to a requested exemption or rule change.

The proposed change is consistent with the defense-in-depth philosophy.

The proposed change maintains sufficient safety margins.

When proposed changes increase core damage frequency (CDF) or risk, the increase(s) should be small and consistent with the intent of the Commissions Safety Goal Policy Statement.

The impact of the proposed change should be monitored using performance measurement strategies.

RG 1.174, An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Permanent Plant-Specific Changes to the Licensing Basis, describes a risk-informed approach, 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 identifies an acceptable risk-informed approach, including additional guidance geared toward the assessment of proposed TS CT changes. Specifically, RG 1.177 identifies a three-tiered approach for the evaluation of the risk associated with a proposed CT TS change as shown below.

Tier 1 assesses the risk impact of the proposed change in accordance with acceptance guidelines consistent with the Commissions Safety Goal Policy Statement, as documented in RG 1.174 and RG 1.177. The first tier assesses the impact on operational plant risk based on the change in CDF and change in large early release frequency (LERF). It also evaluates plant risk while equipment covered by the proposed CT is out-of-service, as represented by incremental conditional core damage probability (ICCDP) and incremental conditional large early release probability (ICLERP). Tier 1 also addresses PRA quality, including the technical adequacy of the licensees plant-specific PRA for the subject application. Cumulative risk of the present TS change in light of past applications, or additional applications under review, are also considered, along with uncertainty/sensitivity analysis with respect to the assumptions related to the proposed TS change.

Tier 2 identifies and evaluates any potential risk-significant plant equipment outage configurations that could result if equipment, in addition to that associated with the proposed license amendment, are taken out of service simultaneously, or if other risk-significant operational factors, such as concurrent system or equipment testing, are also involved. The purpose of this evaluation is to ensure that there are appropriate restrictions in place such that risk-significant plant equipment outage configurations will not occur when equipment associated with the proposed CT is implemented.

Tier 3 addresses the licensees overall configuration risk management program (CRMP) to ensure that adequate programs and procedures are in place for identifying risk-significant plant configurations resulting from maintenance or other operational activities and appropriate compensatory measures to avoid such configurations are taken that may not have been considered when the Tier 2 guidance was developed.

Compared with Tier 2, Tier 3 provides additional coverage to ensure that risk-significant plant equipment outage configurations are identified in a timely manner and that the risk impact of out-of-service equipment is appropriately evaluated prior to performing any maintenance activity over extended periods of plant operation. Tier 3 guidance can be satisfied by 10 CFR 50.65(a)(4), Requirements for monitoring the effectiveness of maintenance at nuclear power plants, (Maintenance Rule), which requires a licensee to assess and manage the increase in risk that may result from activities such as surveillance testing, and corrective and preventive maintenance, subject to the guidance provided in RG 1.177, Section 2.3.7.1, and the adequacy of the licensees program and PRA model for this application. The CRMP is established to ensure that equipment removed from service prior to or during the proposed extended CT will be appropriately assessed from a risk perspective.

More specific methods and guidelines acceptable to the staff are also outlined in RG 1.177 for assessing risk-informed TS changes. Specifically, RG 1.177 provides recommendations for utilizing risk information to evaluate changes to TS CTs and surveillance test intervals with respect to the impact of the proposed change on the risk associated with plant operation.

RG 1.177 also describes acceptable implementation strategies and performance monitoring plans to help ensure that the assumptions and analysis used to support the proposed TS changes will remain valid.

In addition, a licensee should define an implementation and monitoring program such that there is assurance the impact of the change remains consistent with the reliability and availability as originally evaluated for the proposed change. The monitoring program should include means to adequately track the performance of equipment that, when degraded, can affect the conclusions of the licensees evaluation for the proposed licensing basis change. RG 1.174 states that monitoring performed in accordance with the Maintenance Rule can be used when the monitoring performed under the Maintenance Rule is sufficient for the SSCs affected by the risk-informed application.

3.0 TECHNICAL EVALUATION

Two separate evaluations are presented below to address both the deterministic and probabilistic risk assessment (PRA) considerations.

3.1 Deterministic Evaluation 3.1.1 Description of the Proposed Change TS 3.8.7, Action A.1, currently allows only 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to repair an inoperable Division 1 or 2 inverter and return it to service. TS 3.8.7, Action B.1, requires that, with one or more Division 3 or 4 inverters inoperable, declare high pressure core spray system (HPCS) inoperable immediately. HPCS must be restored to operable within 14 days. This effectively results in a 14-day CT for the Division 3 and 4 inverters. The licensee stated that this provides sufficient time for on-line maintenance and post-maintenance testing should it be required for Division 3 or 4. The proposed change would revise the CT of Required Action A.1 of TS 3.8.7, Inverters -

Operating, from the current 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to 7 days for Division 1 or 2 inverter inoperable. The licensee stated that the proposed change would support on-line corrective maintenance of the NSPS inverters. The licensee further stated that the current CT for restoration of an inoperable Division 1 or 2 NSPS inverter is insufficient to support on-line corrective maintenance and post-maintenance testing. Implementation of this proposed CT extension would provide the following benefits: (1) improve NSPS inverter availability during shutdown, (2) reduce plant refueling outage duration, and (3) allow performance of periodic NSPS inverter maintenance and post-maintenance testing on-line.

3.1.2 Technical Evaluation from Deterministic Approach Perspective The NSPS inverters are the preferred source of power for the uninterruptible 120 VAC buses because of the stability and reliability they provide to safety equipment. Each inverter is supplied from a separate and independent, divisional DC bus. There is one inverter per uninterruptible AC bus, making a total of four divisional inverters. The four safety-related 120 VAC inverter buses support the NSPS instruments. There is an alternate supply to each of these NSPS buses from a safety-related 480 VAC bus. Each inverter contains a solid state transfer switch to select the NSPS bus supply. The DC bus through the inverter is the normal supply. However, the solid-state transfer switch will shift to the alternate AC source automatically if the inverter detects abnormal conditions, such as an internal inverter component failure or for handling fault clearing or inrush current demands. In addition, the inverter contains a manual bypass switch to the alternate AC source that is used during the maintenance alignment or can be used if the solid state transfer switch fails. The DC source provides an uninterruptible power source through the inverter for the instrumentation and controls for the RPS, the ECCS initiation, and miscellaneous equipment isolation.

The inverters ensure the availability of AC electrical power for the instrumentation for the systems required to shut down the reactor and maintain it in a safe condition after an AOO or a postulated DBA. Maintaining the required inverters operable ensures that the redundancy incorporated into the design of the RPS and ECCS instrumentation and controls is maintained.

Operable NSPS inverters require the energization of the Class 1E DC bus, with an output within the design voltage and frequency tolerance limits.

The licensee, in its April 26, 2004, submittal, provided the following evaluation for extending the inverter CT:

The initial conditions of DBA and transient analyses in the CPS Updated Final Safety Analysis Report (UFSAR), Chapter 6, Engineered Safety Features, and Chapter 15, Accident Analyses, assume Engineered Safety Features (ESF) Systems are operable.

The NSPS inverters are designed to provide the required capacity, capability, redundancy, and reliability to ensure the availability of necessary power to the RPS and ECCS instrumentation and controls so that the fuel, reactor coolant system (RCS), and containment design limits are not exceeded. The operability of the NSPS inverters is consistent with the initial assumptions of the accident analyses and is based on meeting the design basis of CPS. This includes maintaining required AC instrument buses operable during accident conditions in the event of an assumed loss of all offsite AC power or all onsite AC power sources, and a worst-case single failure.

With a required inverter inoperable, its associated uninterruptible AC bus is inoperable if not energized. The alternate power supply provides an interruptible source of power to the NSPS instrument buses. A loss of offsite power (LOOP) with an inoperable NSPS inverter (i.e., instrument bus being powered by the alternate power supply) will result in a loss of power to the associated instrument bus. The alternate power is provided from a Class 1E power supply, therefore, upon a LOOP with an inoperable NSPS inverter, power would be restored to the affected instrument bus once the associated diesel generator (DG) re-energizes the Class 1E 480 VAC bus. Following restoration of the 480 VAC bus, all instruments supplied by the instrument bus would be restored with no adverse impact to CPS because no other instrument channels in the opposite train would be expected to be inoperable or in a tripped condition during this time, with the exception of routine surveillances. That is, the inverters would be available in the divisions not powered by the alternate AC source. In order for the instrument bus to remain de-energized, the associated DG would have to fail, there would have to be a failure to re-energize the alternate 480 VAC bus powering the instrument bus, or the alternate source would have to fail to energize the instrument bus (i.e., failure of the step-down transformer or isolation transformer).

Based on the above, it has been demonstrated that in the event of a failure to re-energized the 480 VAC bus or of a transformer failure, the most significant impact on the unit is the failure of one train of ESF equipment to actuate. In this condition, the redundant train of ESF equipment will automatically actuate to mitigate the accident, and the unit would remain within the bounds of the accident analyses. In addition, there would be no adverse impact to the unit because no other instrument channels in the opposite train would be expected to be inoperable or in a tripped condition during this time, with the exception of routine surveillances. Since the probability of these events occurring simultaneously during a planned maintenance window is low, there is minimal safety impact due to the requested extended Completion Time. Therefore, the safety functions associated with the NSPS instrument buses will continue to be met with the power supplied by the alternate AC power source.

The NRC staff finds the licensees analysis acceptable in that there is assurance that the AC instrument buses will remain energized when an instrument bus inverter is removed from service, provided compensatory measures are taken when the instrument bus inverter is out-of-service. The compensatory measures should address the concern that, with an inverter unavailable and the instrument bus being powered from the alternate power supply, instrument power from that train is dependent on power from the emergency DG (EDG) following a LOOP event. Entry into the extended inverter completion time concurrent with EDG routine maintenance could have an adverse impact on plant safety following a LOOP event. In addition, entry into the extended inverter completion time concurrent with planned maintenance on another RPS/ESF actuation system channel could potentially result in a reactor trip and/or ESF actuation.

Based upon the above discussion, the NRC staff requested the licensee to provide compensatory measures taken before and during the time the instrument bus inverter is removed for an extended outage. For any compensatory measure proposed, the staff requested that the licensee identify how these actions would be documented and controlled at the facility. In response to the NRC staffs request, in a letter dated April 18, 2005, the licensee stated that the change to the CT will be used to support on-line corrective maintenance of the NSPS inverters. The licensee discussed the risk associated with performance of maintenance on the NSPS inverters during power operation. As a result, an EDG outage or other RPS or ECCS/Reactor Core Isolation Cooling (RCIC) System actuation logic maintenance activity would not be planned concurrent with a Division 1 or Division 2 NSPS inverter outage., Section 4.0 of the submittal dated April 26, 2004, states that for planned maintenance activities, an assessment of the overall risk of the activity on plant safety, including benefits to system reliability and performance, is performed prior to scheduled work. The assessment includes the following considerations:

Maintenance activities that affect redundant and diverse SSCs that provide backup for the same function are minimized.

The potential for planned activities to cause a plant transient are reviewed and work on SSCs that would be required to mitigate the transient are avoided.

Work is not scheduled that has a potential to exceed a TS Completion Time requiring a plant shutdown. Planning for on-line equipment outages typically provides for a 100%

contingency time within the TS Completion Time.

For Maintenance Rule Program High Risk Significant SSCs, the impact of the planned activity on the unavailability performance criteria is evaluated.

As a final check, a quantitative risk assessment is performed to ensure that the activity does not pose any unacceptable risk. This evaluation is performed using the Level 1 PRA model through use of the online risk assessment tool.

These assessments will be required in accordance with plant procedure, WC-AA-101, On-Line Work Control Process. CPS Operations Shift Management reviews all emergent work to ensure that the work does not invalidate the assumptions made during the work management process. As required by plant procedures, prior to starting any work, the work scope and schedule are critically reviewed to assure that nuclear safety and plant operations are consistent with the expectations of management. Individual work activities that potentially affect plant risk are evaluated by the use of system impact matrices, work document job details, plant drawings, or additional means to effectively determine the overall impact to plant risk levels.

The licensee committed to take the following compensatory actions when a Division 1 or 2 NSPS inverter is inoperable:

Entry into the extended inverter CT will not be planned concurrent with EDG maintenance on the associated train.

Entry into the extended inverter CT will not be planned concurrent with planned maintenance on another RPS or ECCS/RCIC actuation logic channel that could result in that channel being in a tripped condition.

These actions are taken because it is recognized that with an inverter inoperable and the instrument bus being powered by the regulating transformer, instrument power for that train is dependent on power from the associated EDG following a loss of power event. Therefore, in order to ensure appropriate control over these compensatory actions, the licensee will describe these two actions in the TS Bases.

In addition, the licensee will perform the following evaluations as part of the CPS risk management program.

Evaluate simultaneous switchyard maintenance and reliability.

Evaluate concurrent maintenance or inoperable status of any of the remaining three instrument bus inverters for the unit.

Evaluate simultaneous emergency diesel generator maintenance.

These commitments will also be reflected in the CPS TS Bases and associated plant procedures. These Bases changes will be implemented in accordance with TS 5.5.11, Technical Specifications (TS) Bases Control Program, as part of the implementation process for this license amendment upon its approval by the NRC staff.

As stated in RG 1.177, [t]he change may be requested to reduce the unnecessary burdens in complying with current TS requirements, based on the operating history of the plant or industry in general. The NRC staff requested that the licensee provide maintenance (e.g., time to repair) and operating (e.g., constant voltage transformer and inverter failure rates) data for the extended outage application. In response to the staff request, in a letter dated April 18, 2005, the licensee stated that, based on a review of failure data contained in the Institute of Nuclear Power Operations, Nuclear Plant Reliability Data System, and Equipment Performance and Information Exchange System, there have been no forced power reductions or plant shutdowns resulting from a failure of an instrument power system inverter or a regulating transformer at CPS. There has been one recent instance (in August 2004) in which another plant initiated a plant shutdown required by TSs for an inverter failure; however, operability was restored prior to completion of the plant shutdown (beyond 24-hour CT required by TSs).

Inverters have had an extensive history of maintenance and operational issues since they were installed in 1986. A review of the corrective maintenance and elective maintenance records was performed to identify work performed on Division 1, 2, 3, and 4 NSPS inverters. This review indicated that 37 emergent work activities have been completed since installation of the CPS NSPS inverters. The most significant failures occurred during refueling outages, when no generation capability was lost. Of these failures, the longest duration to repair an inverter was 174 hours0.00201 days <br />0.0483 hours <br />2.876984e-4 weeks <br />6.6207e-5 months <br /> (7.25 days). This occurred in August 1998 during CPS's extended sixth refueling outage.

No significant failures of regulating transformers have occurred to date. There have been 7 emergent work activities completed on the regulating transformers since they were installed but none of the failures occurred during power operation. The longest repair duration was 3 days, which occurred in 1997.

In general, inverter reliability issues have been resolved satisfactorily with the establishment of an adequate maintenance program and refurbishment of the units in 1998-1999. In an effort to allow for rapid response to future catastrophic failures of a divisional NSPS inverter, the licensee obtained a spare NSPS inverter in 2001. In addition, the licensee replaced the Division 2 NSPS inverter in the February 2004 refueling outage to correct known deficiencies.

While use of the spare inverter will reduce the time required to repair a failed NSPS inverter, the spare may not be able to be installed and tested in 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The licensee has estimated that a repair or replacement of an inverter would take approximately 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> and, therefore, an allowed outage time of 7 days for completing corrective maintenance and post-maintenance testing will envelope this activity.

The NRC staff examined the information provided by the licensee and the technical basis used to establish the proposed 7-day CT for repairing an inverter. As discussed above, the licensee is requesting additional time in order to perform on-line corrective maintenance activities during power operation. Plant operating experience supports the proposed change to a 7-day CT for an inoperable instrument bus inverter. Therefore, the 7-day CT reflects a reasonable time to complete corrective maintenance and post-maintenance testing. In addition, the AC instrument bus will remain energized by its alternate power supply when an instrument bus inverter is removed from service. Based on these considerations and the compensatory measures listed, the NRC staff concludes that a CT extension from 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to 7 days for an inoperable instrument inverter is acceptable from a deterministic perspective.

3.2 Risk Evaluation 3.2.1 Description of the Proposed Change TS 3.8.7, Action A.1, currently allows 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to repair an inoperable Division 1 or 2 NSPS inverter and return it to service. The licensee stated that the 24-hour limit was based on engineering judgment, the time required to repair, and additional risk to the plant with an inverter inoperable. The proposed changes would revise the CT of Required Action A.1 of TS 3.8.7, Inverter-Operating, from the current 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> for a Division 1 or 2 NSPS inverter inoperable to 7 days.

The extended CT is not being proposed for Division 3 and 4 inverters in that the current CT is adequate to support on-line maintenance. TS 3.8.7, Action B.1, requires that with one or more Division 3 or 4 inverters inoperable, the associated Division 3 ECCS subsystems be declared inoperable. The inoperability of one or more Division 3 or 4 inverters may cause an associated ECCS to be inoperable. However, in the case of an inoperable HPCS, the CT is 14 days. The licensee stated that this effectively results in a 14-day CT for the Division 3 and 4 inverters.

The same effective CT is not applicable for Division 1 or 2.

3.2.2 Review of Methodology Per SRP Chapter 19 and Section 16.1, the NRC staff reviewed the submittal using the three-tiered approach and the five key principles of risk-informed decision making presented in RG 1.177.

3.2.3 Key Information Used in the Review The key information used in the NRC staffs risk evaluation is contained in Attachments 1, 2, and 4, and Appendices A, B, C, and D of the license amendment request, as supplemented by the response dated October 11, 2005, to the NRC staff request for additional information (RAI).

The NRC staff also used the licensees individual plant examination (IPE) and individual plant examination of external events (IPEEE) and associated staff evaluation reports. The NRC staffs evaluation of the licensees proposed amendment to extend the CT for the Division 1 and 2 NSPS inverters from 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to 7 days using the three-tier approach and the principles outlined in RGs 1.174 and 1.177 is presented in the following sections.

3.2.4 Technical Evaluation - Risk The NSPS inverter CT change proposed by the licensee employs a risk-informed PRA approach using risk insights to justify changes to TS CTs. The risk metrics CDF, LERF, and ICLERP used by the licensee to evaluate the impact of the proposed changes are consistent with those presented in RGs 1.174 and 1.177.

The subsections below present each tier and the associated reviews.

3.2.4.1 Tier 1: PRA Capability and Insights The first tier evaluates the impact of the proposed CT extension on plant operational risk based on the CPS PRA model. The Tier 1 staff review involves two aspects: (1) evaluation of the validity of the PRA and its application to the proposed CT extension, and (2) evaluation of the PRA results and insights stemming from its application.

The objective of the PRA quality review is to determine whether the CPS PRA used in evaluating the proposed Division 1 and 2 NSPS inverter CT extension was of sufficient scope and detail. The staff reviewed the information provided in the proposed license amendment request, as well as the findings of the CPS IPE dated September 23, 1992, and the CPS IPEEE dated September 27, 1995.

The licensees Level 1 and 2 PRA was originally developed and submitted as the IPE response to Generic Letter (GL) 88-20, Individual Plant Examination of External Events (IPEEE) for Severe Accident Vulnerabilities. The NRC accepted the IPE for CPS by letter dated March 27, 1997, and noted in the safety evaluation report (SER) that the IPE was complete with regard to the information requested by GL 88-20. The NRC staff concluded that the licensees IPE process was capable of identifying the most likely severe accidents and severe accident vulnerabilities and, therefore, the CPS IPE met the intent of GL 88-20. The NRC staff did note limitations to the licensees IPE that could limit the IPEs usefulness for other regulatory applications. The licensee addressed the PRA limitations identified in the staff SER through subsequent updates involving model changes, sensitivity studies, and plant data updates.

The NRC staff reviewed the CPS IPEEE with particular focus on information concerning the proposed instrument bus inverter CT. The licensee submitted the IPEEE on September 27, 1995. The NRC accepted the IPEEE by letter dated December 6, 2000. The NRC staff concluded that the CPS IPEEE was complete with regard to the information requested by Supplement 4 of GL 88-20, and the IPEEE results were reasonable given the design, history, and operation of the plant.

The revision history for the CPS PRA is given below.

CPS IPE - September 1992 Revision 1 - April 1994 Revision 2 - January 1995 Revision 3 - June 2000 Revision 2003A - August 2003 CPS performed a self assessment of the at-power Level 1 and 2 PRA in July 2000. The self assessment included reviews to identify any required additional documentation or areas of improvement to the baseline PRA. The self assessment used the Nuclear Energy Institute (NEI) checklists and documented the technical elements using the PRA peer review forms.

The CPS received an industry PRA peer inspection and review in August 2000. During this review, the quality of the CPS PRA and documentation completeness was assessed. The PRA peer review certification report was issued in October 2000. The assessment process was developed as part of the Boiling Water Reactor Owners Group PRA Peer Review Certification Program. Revision A-3 of NEI draft Probabilistic Risk Assessment (PRA) Peer Review Process Guidance, dated June 2, 2000, was used as the basis of the review.

The latest revision, 2003A PRA model, provides a resolution for all five A PRA peer review facts and observations (F&Os), and also includes resolution of 32 of the 48 level B comments that were considered risk-significant. Based on the evaluation of the remaining 16 level B comments, the licensee decided not to incorporate these changes in the 2003A revision. This is consistent with the definition for B level F&Os, which are considered important and necessary to address, but may be deferred until the next PRA update. The licensee indicated that all F&Os applicable to the proposed extended NSPS inverter CT were dispositioned. This model also incorporates the CPS extended power uprate of 20 percent and maintenance/

component data based on plant operating experience. The peer review did not identify any items with respect to the inverters. Conservatism was noted with assumptions regarding inverter room cooling requirements. The current PRA revision retains this conservatism.

During February 2003, NRC staff and contractors visited the Exelon Generation Companys office in Warrenville, IL to compare the CPS significance determination process (SDP) Phase 2 notebook and licensees risk model results to ensure that the SDP notebook was generally conservative. The CPS PRA did not include most external initiating events (only modeled fire initiators), so no sensitivity studies were performed to assess the impact of these initiators on SDP color determinations. In addition, the results from analyses using the NRCs draft Revision 3i standard plant analysis risk model for CPS were compared with the licensees risk model.

The benchmark visit identified that there was good correlation between the Phase 2 SDP notebook and the licensees PRA. The results indicate that the CPS Phase 2 notebook was generally more conservative in comparison to the licensees PRA. The revision 1 SDP notebook captured 88 percent (results matched or overestimated the licensees PRA by one order of magnitude) of the risk significance of inspection findings. The NRC staff noted that the licensees PRA staff was very knowledgeable of the plant model and provided very helpful comments during the benchmark visit.

The licensee states that the current CPS PRA model revision 2003A has been maintained current and represents current plant configuration, plant operating history, and component failure data. In support of the proposed Division 1 and 2 NSPS inverter CT increase, the licensee evaluated the CPS PRA to ensure that those elements of the PRA sensitive to inverter maintenance are adequate for the evaluation of inverter CTs. The licensee reviewed aspects of the PRA including LOOP, offsite power recovery, operator actions, and failure rates of EDGs, maintenance unavailabilities, and common cause failures (including inverters).

The licensees PRA update program uses Exelon Training and Reference Manual (T&RM)

ER-AA-600-1015, Full Power Internal Events PRA Model Update, to maintain the PRA.

This procedure specifically addresses design changes, plant procedure changes and calculation revisions that may impact PRA modeling assumptions or results. The licensee indicated that potential changes are evaluated based on significance, with PRA updates typically performed on 3-year intervals. The licensee also stated that the goal of the risk management program is to have the internal events PRA represent the American Society of Mechanical Engineers capability II or higher as addressed in Exelon procedure T&RM ER-AA-600-1011, Risk Management Program.

Based on the above discussion, the NRC staff concludes that the licensee adequately addressed the issue of PRA quality and the PRA is of sufficient scope and detail to estimate the risk measures associated with the proposed Division 1 and 2 NSPS inverter 7-day CT.

3.2.4.2 PRA Results and Insights One approach to demonstrate that the risk impact of the proposed change is acceptable is to show that the licensing basis meets the key principles set forth in RG 1.174 for the proposed change. One of these principles is to show that when the proposed change results in an increase in CDF or LERF, the increased risk is small. In addition, the impact of the proposed change should be monitored using performance measurement strategies. RG 1.174 and RG 1.177 provide acceptance guidelines for meeting the above principles. Specifically, those guidelines include CDF, LERF, ICCDP, and ICLERP.

7-Day CT for Division 1 and 2 NSPS Inverters Risk Metric Acceptance Guideline*

PRA Results CDF

<1.0E-6/reactor year 3.0E-8/reactor year LERF

<1.0E-7/reactor year 4.0E-9/reactor year ICCDP (Div 1 Inverter)

<5.0E-7 1.0E-7 ICLERP (Div 1 Inverter)

<5.0E-8 7.7E-9 ICCDP (Div 2 Inverter)

<5.0E-7 ICLERP (Div 2 Inverter)

<5.0E-8

• Acceptance guidelines for very small changes. Acceptance guidelines for small changes are an order of magnitude higher. **Minimal results based on the licensee's model quantification and truncation limits.

A comparison of the risk impacts for CPS shows that the increases in CDF, LERF, ICCDP, and ICLERP are within the RG 1.174 acceptance guidelines. The above results indicate that the proposed extended Division 1 and 2 NSPS inverter CT has a very small quantitative impact on plant risk. The cycle time was based on a 24-month fuel cycle (accounting for planned and unplanned plant outages). The licensee's risk evaluation assumes that the proposed CT of 7 days is used in its entirety and is limited to only once per inverter, per fuel cycle. The licensees average CDF estimate is based on inverter maintenance once a fuel cycle.

Therefore, the potential exists to exceed the yearly CDF and LERF without schedule restrictions. However, in practice, the licensees policy is not to enter a TS CT unless the maintenance can be performed within half the proposed CT (3.5 days).

The risk metric results for the Division 1 and 2 NSPS inverters indicate asymmetry in that the Division 1 NSPS inverter shows higher estimates of ICCDP and ICLERP. The differences are due to the RCIC system being dependent on NSPS Division 1 for SBO scenarios. Based on the above, the staff concludes that the increase in risk, based on the proposed Division 1 NSPS inverter CT extension, is expected to be very small and meets the acceptance guidelines of RGs 1.174 and 1.177.

The licensee evaluated the proposed Division 1 and 2 NSPS inverter CTs impact on previous submittals, including the risk-informed extended EDG CT and extended power uprate submittal.

The licensee noted that the risk impact of previous CPS submittals is considered in the proposed extended NSPS inverter CT. The licensee also provided discussions showing that previous risk-informed assumptions are being maintained based on licensee monitoring and also presented information on plant changes shown to decrease plant risk. Based on the above, the licensees cumulative risk evaluation is consistent with the guidance given in RG 1.174 and is, therefore, acceptable.

3.2.4.3 External Events The licensee evaluated the proposed Division 1 and 2 NSPS inverter CT extension for its potential impact on external events including fire, seismic events, high winds, floods and other (HFO) events. These events are discussed below.

The internal fire risk was evaluated as part of the CPS IPEEE submittal. The licensee used the Electric Power Research Institute (EPRI) Fire-Induced Vulnerability Evaluation Methodology and the Fire Risk Analysis Implementation Guide screening approaches to perform the CPS fire IPEEE PRA study. Based on the IPEEE, of the dominant fires contributing to the CDF, the Switchgear rooms and main control room are the major contributors to fire risk and are included in scenarios for a fire-induced LOOP. The internal fire CDF, summed over all unscreened zones, is estimated to be 3.64E-6/year.

The licensee did a qualitative evaluation of the fire risk due to the proposed Division 1 and 2 NSPS inverter CT. The licensee then determined that the internal events risk impact for the inverter CT is dominated by SBO scenarios. The licensee identified fire areas that have the potential to cause a LOOP/SBO. The licensee confirmed that the identified areas are still representative of the IPEEE analysis. No significant impact on the IPEEE results were identified. To estimate the fire CDF impact, the licensee assessed the dominant fire scenarios from the IPEEE fire analysis and the fraction of SBO and non-SBO events. The IPEEE fire analysis results were then modified based on the internal CDF impact (SBO and non-SBO results) and applied to the baseline fire CDF. Based on the licensees estimates, the IPEEE fire CDF increase is estimated at 2.59 percent (9.43E-8/year) with an estimated ICCDP of 1.81E-9.

However, the licensee stated in their RAI response that not all of the areas identified considered fire-induced LOOP/SBO. Based on this, the licensee committed to compensatory fire risk measures as identified in Section 3.3 of this SE.

For the seismic IPEEE analysis, CPS is categorized as a 0.3g focused-scope plant (per NUREG-1407). The plant seismic design basis earthquake is 0.25g for a safe shutdown earthquake (SSE). The plant seismic design inputs were based on RG 1.60, "Design Response Spectra for Seismic Design of Nuclear Power Plants," response spectra anchored at the SSE (0.25g). The licensee used the EPRI seismic margins assessment methodology as described in EPRI NP-6041-SL, A Methodology for Assessment of Nuclear Power Plant Seismic Margin, with enhancements specified in NUREG-1407. The licensee did not quantitatively estimate a seismic CDF contribution, since a seismic margins assessment is a deterministic review process. The licensee's seismic margin analysis indicated that the overall high confidence of low probability of failure plant capacity was equal to, or greater than, the review level earthquake value of 0.3g. The evaluation identified no potential vulnerabilities in the safe shutdown SSCs in the two shutdown paths selected. No plant improvements in this area were identified. Therefore, the proposed Division 1 and 2 NSPS inverter CT extension has no impact on the seismic qualification of the inverters.

CPS was designed and constructed in accordance with the 1975 SRP criteria, and the focus of the HFO IPEEE review was to show conformance with the SRP criteria. The licensee used the progressive screening approach, as described in NUREG-1407, to assess HFO. As stated in the IPEEE, the licensee did not quantitatively estimate the CDF contribution from HFO events since these events were screened using the NUREG-1407 screening approach. The licensee considered the need to perform additional evaluations on the potential effects of other external events including lightning, severe temperature transients, ice, hail, snow, external fires, and others. The licensee reported that lightning protection is provided as a part of the CPS plant design and did not need to be reviewed further, and that the other issues noted were not required for the plant under the guidance in NUREG-1407. Therefore, the proposed Division 1 and 2 NSPS inverter extended CT does not impact the HFO conclusion of the IPEEE.

Based on the above, the NRC staff concludes that the increase in risk from fire, seismic and HFO events based on the proposed Division 1 and 2 NSPS inverter CT extension is expected to be insignificant, and that the overall risk is adequately represented by the contributions from internal initiating events.

3.2.4.4 Shutdown The licensee for CPS has not developed a shutdown model. However, with the ability to complete more Division 1 and 2 NSPS inverter maintenance activities at power, there will be a corresponding reduction in shutdown risk that is not reflected in the risk estimates provided by the licensee due to improved inverter availability. The licensee relies on its configuration risk management program and a qualitative model to assess the potential impacts to shutdown risk.

With inverter maintenance activities performed at-power, the availability of the inverters during shutdown should improve. Therefore, with respect to the proposed 7-day Division 1 and 2 NSPS inverter CT, the shutdown risk averted may provide a qualitative risk benefit, but is not credited or quantified in the risk evaluation presented by the licensee. In addition, with more time to perform corrective inverter maintenance on-line, transition risk will also be reduced.

3.2.4.5 PRA Uncertainty As discussed in RG 1.174 and NUREG/CR-6141, Handbook of Methods for Risk-based Analyses of Technical Specifications, a licensee can perform sensitivity studies to provide additional insights into the uncertainties related to the proposed CT extension, and demonstrate compliance with the guidelines and evaluate uncertainties related to modeling and completeness issues.

The licensee evaluated CDF, LERF, ICCDP, and ICLERP sensitivities to the base case with the sensitivities showing relatively small or negligible impacts on ICCDP and ICLERP. Because the Division 2 NSPS inverter was not limiting in the analysis, the licensee evaluated sensitivity cases for the Division 1 NSPS inverter only. The results indicate that changes in the alternate AC source transformer failure probability resulted in negligible impact on the analysis results.

Increasing the unavailability of AC power sources (LOOP frequencies and DG-A) increased both ICCDP and ICLERP. As stated previously, this is because with a Division 1 NSPS inverter out-of-service, any failure of the alternate AC supply results in RCIC failure. Because of this, the dominant sequences affecting the increase in CDF are those that involve the loss of the Division 1 NSPS inverter with LOOP initiators leading to a SBO. Increasing the LOOP frequency by a factor of 3 results in ICCDP and ICLERP values still within the acceptance guidance of RG 1.177. Increases in DG failure probability and the common cause factors for the Division 1 DG by a factor of 3 also results in the acceptance guidelines for ICCDP and ICLERP still being met. It was also shown by the licensee that changes in scram failure probability had minimal impact on the risk estimates for ICCDP and ICLERP. Changes in CPS plant availability of approximately 11 percent also had a small impact on the risk results.

The above shows that the risk resulting from the proposed 7-day inverter CT is relatively insensitive to uncertainties, and therefore, it is acceptable.

3.2.5 Tier 2: Avoidance of Risk-Significant Plant Configurations The licensees evaluation results did not identify any components that would result in a significant change in risk or require maintenance restrictions, when out-of-service concurrent with either Division 1 or 2 NSPS inverters. The licensees analysis identified Tier 2 measures as identified by the licensees CRMP, but no compensatory measures were committed to by the licensee. Also, the licensee evaluated the risk achievement worth (RAW)for basic events with the Division 1 NSPS inverter out-of-service. Using the criteria that a substantial change in RAW is a RAW value greater than 2, the licensee identified basic events that met the criteria for a substantial change but did not provide compensatory measures based on the RAW analysis.

However, in its October 11, 2005, response to the staff RAI, the licensee proposed and committed to additional compensatory measures. These additional commitments are identified in Section 3.3 of this SE. In addition, LCO 3.03 must be entered if one or more additional inverters are inoperable. RG 1.177, Section 2.3.7.2, Key Components of the CRMP, Item 4, states that Tier 2 commitments apply only for planned maintenance, but should be evaluated as part of the Tier 3 assessment for unplanned occurrences. Since the extended inverter CT will be used by the licensee for emergent corrective maintenance, the additional commitments should be included in the licensees Tier 3 evaluation.

3.2.6 Tier 3: Risk-Informed Configuration Risk Management The CPS CRMP was developed to be consistent with the Maintenance Rule, 10 CFR 50.65(a)(4). The CPS program is documented in procedure WC-AA-101, On-Line Work Control Process, to help ensure the risk effect of out-of-service equipment is appropriately evaluated prior to performing a maintenance activity. The licensee indicates this program requires an integrated review (i.e., both probabilistic and deterministic) to identify risk-significant plant equipment outage configurations in a timely manner both during the work management process and for emergency conditions during normal plant operation. Consideration is given to equipment unavailability and operational activities like testing and weather conditions.

This program includes provisions for performing a configuration-dependent assessment of the overall impact on risk of proposed plant configurations prior to, and during, the performance of maintenance activities that remove equipment from service. Risk is reassessed if an equipment failure/malfunction or emergent condition produces a plant configuration that has not been previously assessed. The assessment includes the following considerations:

Maintenance activities that affect redundant and diverse SSCs that provide backup for the same function are minimized.

The potential for planned activities to cause a plant transient are reviewed and work on SSCs that would be required to mitigate the transient are avoided.

Work is not scheduled that has a potential to exceed a TS Completion Time requiring a plant shutdown. Planning for on-line equipment outages typically provides for a 100% contingency time within the TS Completion Time.

For Maintenance Rule Program High Risk Significant SSCs, the impact of the planned activity on the unavailability performance criteria is evaluated.

As a final check, a quantitative risk assessment is performed to ensure that the activity does not pose any unacceptable risk. This evaluation is performed using the Level 1 PRA model through use of the online risk assessment tool.

Emergent work is reviewed by operations shift management to ensure that work does not invalidate the assumptions made during the work management process. The licensee also stated that the following compensatory items may be considered in work planning activities:

Evaluate simultaneous switchyard maintenance and reliability.

Evaluate concurrent maintenance or inoperable status of any of the remaining three instrument bus inverters for the unit.

Evaluate simultaneous emergency diesel generator maintenance.

Perform inverter on-line maintenance simultaneously with RCIC work window to minimize overall integrated risk.

RG 1.174 states that an implementation and monitoring plan should be developed to ensure that the impact of the proposed change continues to reflect the actual reliability and availability of the inverters evaluated to support the proposed extended Division 1 and Division 2 inverter CT. Monitoring performed in conformance with the Maintenance Rule, can be used when such monitoring is of SSCs affected by the risk-informed application. Therefore, to ensure that the proposed extended CT does not degrade operational safety over time, should equipment not meet its performance criteria, an evaluation is required as part of the Maintenance Rule.

The licensee stated that, per the guidance in NUMARC 93-01, Industry Guidance for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, the NSPS inverters are considered risk-significant and, therefore, the reliability and unavailability of the inverters are monitored to demonstrate that their performance is adequate. If the licensees preestablished reliability or availability performance goals are exceeded for the NSPS inverters, consideration must be given to 10 CFR 50.65(a)(1) requirements, including increased management attention and goal setting, in order to restore inverter reliability and availability to an acceptable level.

Based on licensee information, the CPS NSPS inverters experienced extensive maintenance and operational issues that resulted in the inverters being identified as subject to the requirements of the Maintenance Rule, 10 CFR 50.65(a)(1), in 1994 due to repetitive NSPS inverter fuse failures. The licensee stated that fuse failures were subsequently resolved with NSPS inverter refurbishment. The NSPS inverters were again identified as subject to the requirements of the Maintenance Rule, 10 CFR 50.65(a)(1), due to spurious Division 2 NSPS inverter transfers to the alternate source. The licensee stated that the root cause of the poor inverter performance was due to incorrect and insufficient maintenance. The licensee took corrective action, including the refurbishment of the inverters, in 1998 - 1999. With the establishment of an adequate maintenance program, inverter performance has improved such that the inverters were identified as subject to the requirements of the Maintenance Rule, 10 CFR 50.65(a)(2), in 2000. The licensee also replaced the Division 2 NSPS inverter in February of 2004. The removed Division 2 NSPS inverter is scheduled for refurbishment and will be designated as a spare, allowing expedited repair for any catastrophic failure of a Divisional NSPS inverter.

The NSPS inverters are currently in the 10 CFR 50.65(a)(2) category, meaning that the inverters are meeting established performance goals. The actual NSPS inverter reliability and availability are monitored and periodically evaluated to assess the effect of the proposed CT extension on established inverter Maintenance Rule goals.

The NRC staff finds that the licensees online work control program to control risk is capable of adequately assessing the activities being performed to ensure that high-risk plant configurations do not occur and/or compensatory actions are implemented if a high-risk plant configuration or condition should occur and that NSPS inverter reliability and availability are monitored and evaluated. As such, the licensees program meets the Tier 3 guidance of RG 1.177 for a CRMP and an implementation and monitoring program.

3.3 Regulatory Commitments The following regulatory commitments were identified by the licensee through RAI responses.

They will be implemented as part of the implementation process for this license amendment.

(a)

From the April 18, 2005, RAI response (1)

Revise TS Bases section 3.8.7 and the applicable procedure(s) to reflect the following evaluations as part of the risk management program.

C Evaluate simultaneous switchyard maintenance and reliability.

C Evaluate concurrent maintenance or inoperable status of any of the remaining three instrument bus inverters for the unit.

C Evaluate simultaneous emergency diesel generator maintenance.

(2)

Revise TS Bases section 3.8.7 to incorporate the following compensatory actions that should be taken when a Division 1 or 2 NSPS inverter is inoperable.

C Entry into Required Action A.1 will not be planned concurrent with EDG maintenance on the associated train.

C Entry into Required Action A.1 will not be planned concurrent with planned maintenance on another RPS or ECCS/RCIC actuation logic channel that could result in that channel being in a tripped condition.

(b)

From the October 11, 2005, and May 19, 2006, RAI responses (1)

When the Division 1 NSPS inverter is unavailable, the following compensatory actions will be taken.

C Entry into the extended inverter CT will not be planned concurrent with shutdown service water maintenance.

C Entry into the extended inverter CT will not be planned concurrent with Division 3 (HPCS) maintenance including the Division 3 battery or charger.

C Entry into the extended inverter CT will not be planned concurrent with maintenance unavailability of the Division 1 or 2 DC components (i.e., batteries or chargers).

C Entry into the extended inverter CT will not be planned concurrent with maintenance unavailability of the Division 1 NSPS regulating transformer.

The TS Bases section 3.8.7 and applicable CPS procedure(s) will be revised to reflect the need to take the above compensatory actions.

(2)

When either a Division 1 or 2 NSPS inverter is unavailable, the following compensatory action will be taken.

C Entry into the extended inverter CT will not be planned concurrent with planned maintenance on another RPS channel that could result in that channel being in a tripped condition.

The TS Bases section 3.8.7 and applicable CPS procedure(s) will be revised to reflect the need to take the above compensatory action.

(3)

During Modes 1, 2, and 3, should the Division 1 NSPS inverter be removed from service for more than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />, then within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of removal from service the following will be performed.

C Conduct walkdowns in Fire Zones A-2K, A-3d, A-3f, CB-1f, CB-2, CB-3a, CB-4, R-1i (southwest corner of R-S line), R-1p (southwest corner of R-S line), R-1t, and T-1f (south end of R-S line), confirming that there are no unauthorized combustibles or other unusual fire hazards in these areas.

C Inspect Main Control Room panel 1H13-P870, confirming that there are no unauthorized combustibles or other unusual fire hazards in the cabinet.

C Ensure that fire protection sprinklers are available for Fire Zones CB-2, CB-3a, and CB-4.

C Hot work will not be permitted in the above areas during the extended maintenance period.

This commitment will be incorporated into the appropriate CPS procedure(s).

3.4 Summary The risk impact of the proposed 7-day CT for the Division 1 and 2 NSPS inverters at CPS, as estimated by CDF, LERF, ICCDP, and ICLERP is consistent with the acceptance guidelines specified in RG 1.174, RG 1.177, and NRC staff guidance outlined in Chapter 16.1, Risk-Informed Decisionmaking: Technical Specifications, of NUREG-0800. The NRC staff finds that the risk analysis methodology and approach used by the licensee to estimate the risk impacts were reasonable and of sufficient quality. The licensees configuration risk management program uses 10 CFR 50.65(a)(4) to manage plant risk when an NSPS inverter is taken out-of-service. NSPS inverter reliability and availability will also be monitored and assessed under the Maintenance Rule 10 CFR 50.65 to confirm that performance continues to be consistent with the assumptions used in the analysis for extended inverter CTs. Based on the above, the staff finds that the proposed 7-day CT is acceptable for the NSPS inverters at CPS.

4.0 STATE CONSULTATION

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

5.0 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 previously issued a proposed finding that the amendment involves no significant hazards consideration, and there has been no public comment on such finding (69 FR 32072; June 8, 2004). 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.

6.0 CONCLUSION

The NRC staff has concluded, based on the considerations discussed above, that: (1) there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, (2) such activities will be conducted in compliance with the Commission's regulations, and (3) the issuance of the amendments will not be inimical to the common defense and security or to the health and safety of the public.

Principal Contributors: C. Doutt D. Nguyen Date: May 26, 2006