NL-11-1628, Technical Specification Revision Request for TS 3.7.14 Engineered Safety Features (ESF) Room Cooler and Safety-Related Chiller System

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Technical Specification Revision Request for TS 3.7.14 Engineered Safety Features (ESF) Room Cooler and Safety-Related Chiller System
ML113550489
Person / Time
Site: Vogtle Southern Nuclear icon.png
Issue date: 12/19/2011
From: Ajluni M
Southern Nuclear Operating Co
To:
Office of Nuclear Reactor Regulation, Document Control Desk
References
NL-11-1628
Download: ML113550489 (41)
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Text

Mark J. Ailuni, P.E. Southern Nuclear Nuclear licensing Director Operating Company, Inc.

40 Invern ess Center Parkway Post Office Box 1295 Birm ingham, Alaba ma 35201 Tel 205.992.7673 Fax 205.992.7885 December 19, 2011 SOUTHERN ' \

COMPANY Docket No.: 50-425 NL-11-1628 U. S. Nuclear Regulatory Commission AnN: Document Control Desk Washington, D. C. 20555-0001 Vogtle Electric Generating Plant - Unit 2 Technical Specification Revision Request for TS 3.7.14 Engineered Safety Features (ESF)

Room Cooler and Safety-Related Chiller System Ladies and Gentlemen:

In accordance with 10 CFR 50.90, "Application for amendment of license, construction permit, or early site permit," Southern l\Iuclear Operating Company (SNC) proposes to revise the Vogtle Electric Generating Plant (VEGP) Unit 2 Technical Specifications (TS), Appendix A to Operating License I\IPF-81.

The proposed TS change would revise TS 3.7.14, "Engineered Safety Features (ESF) Room Cooler and Safety-Related Chiller System" such that, with one ESF room cooler and safety-related chiller train inoperable, the allowed Completion Time for Condition A is extended from 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to 9 days, on a one-time only basis. The 9-day Completion Time will allow time for a 180-month overhaul preventive maintenance of the Unit 2 Train 2B safety-related chiller system to be performed during power operation rather than during a refueling outage. Also proposed is an editorial change to delete a note added as an emergency change to TS 3.7.14 per SNC letter NL-1 0-1609 dated August 18, 2010. That note was for a one-time use and is no longer needed.

A discussion of the proposed TS change, the basis for the change, and Significant Hazards Considerations are provided in Enclosure 1. Enclosures 2 and 3 provide the marked-up and clean-typed TS pages. Enclosure 4 has a commitment table and Enclosure 5 supplements Enclosure 1 by providing a discussion of probabilistic risk assessment capability for VEGP. Enclosure 6 has the list of ESF room coolers served by the Train 2B safety-related chiller system.

SNC has evaluated the proposed TS change and has determined that it does not involve a significant hazards consideration as defined in 10 CFR 50.92.

In order to perform the maintenance during power operation rather than during an outage, SI\lC requests that the proposed TS change be reviewed and approved on or before December 21 ,2012. Following approval, the preventive maintenance will be completed prior to the refueling outage scheduled to begin

U. S. Nuclear Regulatory Commission NL-11-1628 Page 2 on March 10, 2013. The proposed change will be implemented within 30 days of issuance of the amendment.

Mr. M. J. Ajluni states he is Nuclear Licensing Director of Southern Nuclear Operating Company, is authorized to execute this oath on behalf of Southern Nuclear Operating Company and to the best of his knowledge and belief, the facts set forth in this letter are true.

This letter contains NRC commitments (reference Enclosure 4). If you have any questions, please contact Mr. B. D. McKinney at (205) 992-5982.

Respectfully submitted, rvu~~

M. J. Ajluni Nuclear Licensing Director Sworn to and subscribed before me this --1.L day of D ece I'M /3~ &",2011.

~t;2~.

Notary PUb/IC My commission expires: I / I/ 30/ /S I

MJA IJLS

Enclosures:

1. Basis for Proposed Change
2. Marked-Up Technical Specifications Page
3. Clean Typed Technical Specifications Page
4. Commitment Table
5. Discussion of Probabilistic Risk Analysis Capability
6. ESF Room Coolers Served by Train 2B Safety-Related Chiller System cc: Southern Nuclear Operating Company Mr. S. E. Kuczynski, Chairman, President & CEO Mr. D. G. Bost, Chief Nuclear Officer Mr. T. E. Tynan, Vice President - Vogtle Ms. P. M. Marino, Vice President - Engineering RType: CVC7000 U. S. Nuclear Regulatory Commission Mr. V. M. McCree, Regional Administrator Mr. D. H. Jaffe, NRR Senior Project Manager - Vogtle Mr. L. M. Cain, Senior Resident Inspector - Vogtle State of Georgia Mr. Allen Barnes, Environmental Director Protection Division

Vogtle Electric Generating Plant Unit 2 Technical Specification Revision Request for TS 3.7.14 Engineered Safety Features (ESF)

Room Cooler and Safety-Related Chiller System Enclosure 1 Basis for Proposed Change to NL-11-1628 Basis for Proposed Change Table of Contents

1. Summary Description
2. Detailed Description
3. Technical Evaluation
4. Regulatory Evaluation 4.1 Significant Hazards Consideration 4.2 Applicable Regulatory Requirements I Criteria 4.3 Conclusions
5. Environmental Consideration
6. References E1-1

Enclosure 1 to NL-11-1628 Basis for Proposed Change

1. Summary Description This licensing amendment request is to amend Vogtle Electric Generating Plant (VEGP) Unit 2 Operating license NPF-81.

The proposed change to the Technical Specifications (TS) would revise TS 3.7.14, "Engineered Safety Features (ESF) Room Cooler and Safety-Related Chiller System" such that, with one ESF room cooler and safety-related chiller train inoperable, the allowed Completion Time (CT) for Condition A is extended from 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to 9 days, on a one-time only basis. The 9-day allowable CT time will allow time for an overhaul preventive maintenance (PM) of the Unit 2 Train 28 essential chiller to be performed during power operation rather than during a refueling outage. The PM would be completed prior to the refueling outage scheduled to begin on March 10, 2013. Also proposed is an editorial change to delete a note added as an emergency change to TS 3.7.14 per SNC letter NL-10-1609 dated August 18, 2010. That note was for a one-time use and is no longer needed.

2. Detailed Description

Background

This proposed change is requested to allow maintenance on the safety-related Essential Chilled Water System (ECWS) during power operation (Modes 1-4) rather than during a refueling outage because the current 72-hour CT is not long enough to perform the required chiller overhaul PM.

Allowing the maintenance to be performed during power operation allows more focused management attention for the planning, maintenance implementation, and return to service. The essential chillers are very large, 300-ton capacity units; as such, special rigging and lifting preparations are required for component removal and re-installation, and the limited room size constrains some activities to being performed in series.

The proposed technical specification change is for one-time for maintenance activities requiring more than the 72-hour CT. VEGP has committed to Risk-Informed Initiative 4b (reference SNC letter NL-11-1297). It is expected that implementing Risk-Informed TS Initiative 4b will negate the need for future TS changes regarding ECWS CTs.

The ESF room coolers and ECWS are not included in the Vogtle Probabilistic Risk Assessment (PRA) model due to their negligible impact on the reliability of PRA-credited functions. The Incremental Conditional Core Damage Probability and Incremental Conditional Large Early Release Probability are assessed to be negligible (zero for the model) when the ESF room coolers and ECWS are in a degraded one-train mode of operation such as that proposed by this request.

To ensure unit reliability: each of these chillers is run a minimum of 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br /> per month to support the control room emergency filtration system (CREFS) operability run; quarterly actuation logic tests are performed to start each chiller; PMs are performed on controls and breakers for the chillers on 18- and 54-month frequencies; inspections and motor megger testing are performed on a 54-month frequency; monthly engineering walk downs are performed; and oil sampling is done every 54 months to check for wear metals and oil degradation.

E1-2

Enclosure 1 to NL-11-1628 Basis for Proposed Change The essential chiller overhaul PMs, performed on a 180-month frequency, include regasketing and mechanical inspection of internal components. The second round of these overhaul PMs has been completed for essential chillers 1A, 2A, and 1B. These overhaul PM activities help enhance the reliability of the Train 1A, 2A, and 1B ECWS during the proposed on-line maintenance of Train 2B.

All essential chillers are Maintenance Rule A2 status, and have therefore demonstrated acceptable performance.

Maintenance of the nuclear service cooling water (NSCW) side of essential chiller 2B, including cleaning and eddy current testing of the Train 2B condenser tubes, was successfully completed during the fall 2011 refueling outage and is not related to this TS change request. Those maintenance activities included proactively plugging two condenser tubes due to tube thinning.

The overhaul PM has been performed at least one time for all of the essential chillers. The first round of overhaul PMs was completed in the late 1990s. The last complete overhaul PM of the 2B essential chiller was completed in the March-April 1998 time frame. The second round of overhaul PMs is currently in progress with three of the four essential chillers completed, including the overhaul PM performed on the 2A essential chiller during the repair of a tube leak in August, 2010.

This relatively recent 2A essential chiller overhaul helps ensure the reliability of the 2A chiller during the requested extension of CT for the 2B essential chiller.

The essential chillers have been in service for approximately 25 years. During that time only five tubes (all condenser tubes) have been plugged in all of the essential chillers served by NSCW .

Specifically, two tubes in the condenser have been plugged in the 2B chiller, two tubes in the condenser have been plugged in the 2A chiller, and one tube in the condenser plugged in the 1B chiller. No tubes have been required to be plugged in the condenser in the 1A chiller. Of the five plugged tubes, only one tube had failed while four were tested and found to have defects. Each chiller condenser has 479 tubes, and the plugging limit is ten percent of tubes (that is, a plugging limit of 47 tubes). Eddy current testing has demonstrated that the Train 1A, 2A, and 1B evaporator and condenser tubes are in good condition. Essential chiller condenser and evaporator leakage have historically been within acceptable parameters and have not impacted operation, with the exception of the 2A essential chiller tube leak in 2010.

This proposed change to the TS is similar to the previous 2A essential chiller emergency TS revision request for the 2A chiller to be inoperable for 14 days to repair water leakage into the refrigerant side and to replace the chiller hermetic compressor motor (SNC letter NL-10-1609 and NL-10-1623 dated August 18, 2010), for which Southern Nuclear Operating Company (SNC) received NRC approval on August 19, 2010.

Also proposed is an editorial change to delete a note added as an emergency change to TS 3.7.14 per SNC letter I\IL-10-1609 dated August 18, 2010. That note was for a one-time use and is no longer needed.

3. Technical Evaluation Proposed Change Add a note to allow a one-time change to TS LCO 3.7.14 Condition A CT for the 2B ESF room cooler and safety-related chiller train to extend it from 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to 9 days for the period from the E1-3 to NL-11-1628 Basis for Proposed Change implementation of this requested revision until prior to the next Unit 2 refueling outage, scheduled to begin on March 10, 2013. Also proposed is an editorial change to delete a note added as an emergency change to TS 3.7.14 per SNC letter NL-10-1609 dated August 18, 2010. That note was for a one-time use and is no longer needed.

System Description

The ECWS is comprised of two separate, redundant, 100% independent trains. The ESF room coolers and ECWS provide chilled water to ESF equipment room coolers during abnormal, accident, and post accident conditions. The normal chilled water coils in certain ESF room coolers provide cooling to certain rooms during normal operations. The ECWS supplies chilled water to the cooling coils in ESF room coolers and the CREFS.

The ESF room coolers are designed to maintain the ambient air temperature below the environmental qualification rating of the ESF equipment served by the system. Each equipment room is cooled by a room cooler and associated chiller that are powered from the same ESF train as that associated with the equipment in the room. Thus, a power failure or other single failure to one cooling system train will not prevent the cooling of redundant ESF equipment in the other train. For q list of ESF room coolers and areas served by the Unit 2 Train 2B safety related chiller system, see Enclosure 6.

In addition to a manual start capability, automatic cooling of ESF equipment rooms is initiated by three possible signals. Each room cooler will start upon receipt of a high temperature signal from the associated room. Certain room coolers will start upon receipt of an equipment-running signal or a safety injection (SI) signal. The equipment-running Signal is used to provide supplemental cooling for the normal ventilation system in some ESF equipment rooms. The high room temperature signal supplements the normal cooling system function and does not constitute a credited safety function. The SI signal or the equipment-running signal is the credited safety function automatic start and will start only those ESF room coolers which are required to operate during an SI. The ECWS receives an automatic start from the Control Room Isolation (CRI) signal to provide chilled water to the CREFS. The containment spray pump room coolers start when the containment spray pumps start. Containment spray is actuated when containment pressure reaches the Hi-3 setpoint, which may occur following a loss-of-coolant-accident or a steam line break.

The spent fuel pool heat exchanger and pump rooms are cooled by train oriented room coolers with both normal chilled water (NCW) and train-oriented essential chilled water (ECW) COOling coils for each spent fuel pool heat exchanger and pump room cooling train. During normal plant operation, the NCW cooling coil in the room coolers provides the necessary cooling function for both the Train A and Train B spent fuel pool heat exchanger and pump rooms. In the event of loss of the NCW cooling source while Train 2B is inoperable, the Train 2A ECW coil can provide the necessary cooling function for the Train 2A spent fuel pool heat exchanger and pump room.

The ESF room coolers and the ECWS are seismic category 1, are provided with 1E power, and are designed to remain operational during and after a safe shutdown earthquake.

All of the loads served by the 2B ECWS will be considered inoperable as required by LCO 3.0.6.

However, the Conditions and Required Actions of the supported systems (that is, loads) are not required to be entered as allowed by LCO 3.0.6. The 2A ECWS is a separate independent train that provides the required cooling to the equivalent loads in Train 2A, and all of the equipment E1-4

Enclosure 1 to NL-11-1628 Basis for Proposed Change served by the 2A ECWS will be provided the required cooling. Disregarding other unrelated failures, these Train 2A loads will be operable and capable of performing their intended function.

The compensatory measures which are to be put in place to enhance reduction of associated risks related to work on Train 28 equipment (that is, work which could potentially have an adverse impact on the normal chilled water system, the 2A ECWS, or that could affect the availability of the offsite power source) are:

  • screening and limiting of such work to only that deemed necessary to ensure regulatory compliance or to support safe continued plant operation
  • the opening of doors and the installation of fans, as necessary, in selected rooms to mitigate the potential rise in room temperature, in order to facilitate the availability of the associated housed equipment, in the event all chilled water systems are lost These compensatory measures are not credited with maintaining the equipment in the affected room(s) operable but are deemed to be prudent actions.

Need for Technical Specification Change The parts of the essential chiller overhaul PM that are the focus of this proposed TS change are maintenance of the essential chiller water side (cleaning and eddy current testing of the evaporator tubes) and maintenance of the refrigerant side (disassembly, examination, and reassembly of the chillers). These overhaul PM activities require substantially more time than the 72-hour CT currently allowed by TS 3.7.14. Therefore, such work is typically performed during refueling outages. With an allowance for contingencies, these activities may require up to 9 days when performed while the plant is online. This duration would allow time such that the preventive maintenance could be performed with time allowed for recovery in the event that there are complications or unforeseen problems.

Maintenance of the 28 essential chiller will be performed on an expedited basis, but due to the complexity of the activities involved, the 72-hour TS 3.7.14 Condition A LCO CT will not allow sufficient time to complete all needed activities. The work is scheduled to be performed while online, necessitating this request for a one-time TS amendment.

A number of activities are performed during the refrigerant side overhaul PM. The refrigerant is sampled and analyzed for any moisture and metal particles. After disassembling the chiller, a visual inspection and cleaning is performed on components that include the volutes, shaft seal ring assemblies, impeller assemblies, cover assemblies, vane assemblies, and motor bearings. Also included is regasketing of all jOints. After the reassembly, the chiller will be leak checked for any refrigerant leaks. If leaks are detected, the associated boundaries are reworked and the leak check is performed again. Then a deep vacuum is drawn on the machine to remove moisture and also to demonstrate that there is no leakage. Then, the machine is charged with refrigerant. The chiller is functionally tested and returned to service.

Some of the sequential steps (not inclusive) of the chiller overhaul PM and their approximate durations are:

  • Perform clearance and begin overhaul PM - 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br /> E1-5 to NL*11*1628 Basis for Proposed Change
  • Chiller preparation and installation of ground breakers - 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />
  • Remove chiller end bells and inspect tubes - 17 hours1.967593e-4 days <br />0.00472 hours <br />2.810847e-5 weeks <br />6.4685e-6 months <br />
  • Rigging / remove crossover piping - 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />
  • Disassembly and inspection - 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />
  • Reassembly - 42 hours4.861111e-4 days <br />0.0117 hours <br />6.944444e-5 weeks <br />1.5981e-5 months <br />
  • Leak check with N2 - 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />
  • Draw vacuum and hold for 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> - 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br />
  • Charge with refrigerant - 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />
  • Verify electrical connections - 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />
  • Remove equipment / restore normal power to heater - 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />
  • Release clearance / post maintenance function test and 10-hour run - 13 hours1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br /> The scheduled duration for tagout and work, that requires a need for entry into TS 3.7.14 Condition A, is approximately 7 days. To allow for contingencies, such as a need for the chiller hermetic compressor motor replacement (requiring scaffold and rigging) which would require approximately an additional 2 days, a proposed CT of 9 days is being requested.

The PM was originally scheduled for September 18, 2011 (fall 2011 outage) with a late date of March 11, 2013. It was deferred from the fall 2011 outage because of higher priority demands for critical outage resources. This system is not risk significant, and it is expected that if this PM were to be performed online, the work could be managed more effectively and with more management oversight. Note that although an essential chiller is not required to be operable in Modes 5 and 6 per TS 3.7.14, an essential chiller does have to be functional in Modes 5 and 6 to support CREFS (TS 3.7.11).

Also proposed is an editorial change to delete a note added as an emergency change to TS 3.7.14 per SNC letter I\IL-10-1609 dated August 18, 2010. That note was for a one-time use and is no longer needed.

Risk Assessment An assessment was performed to evaluate the acceptability of the proposed continued plant operation while performing the PM of Train 2B ECWS beyond the TS allowed CT. The assessment used the acceptance criteria from Regulatory Guide 1.177, "An Approach for Plant Specific, Risk-Informed Decision Making: Technical Specifications" for the determination of the acceptability of the Incremental Conditional Core Damage Probability (ICCDP) and the Incremental Conditional Large Early Release Probability (ICLERP) figures of merit under the proposed circumstances. The ICCDP and ICLERP represent the change in the Core Damage Frequency (delta CDF) and the Large Early Release Frequency (delta LERF) multiplied by the proposed increase in the CT. It should be noted that the ECWS is not included in the peer reviewed VEGP Probabilistic Risk Assessment (PRA) model due to the negligible impact of the ECWS on the reliability of PRA-credited functions, as discussed below. It follows, therefore, that ICCDP and ICLERF are assessed to be negligible (zero, as modeled) when the ECWS system is in a degraded one train mode of operation such as that proposed by this request.

E1-6 to NL*11*1628 Basis for Proposed Change This assessment has been performed using the peer reviewed VEGP PRA model, and using the NRC's three-tier approach described in RG 1.1 Tl,. The three tiers consist of:

Tier 1 - PRA Capability and Insights Tier 2 - Avoidance of Risk-Significant Plant Configurations, and Tier 3 - Risk-Informed Configuration Risk Management Tier 1: PRA Capability and Insights (Reference Enclosure 5 for a discussion of VEGP PRA capability.)

Risk Evaluation In the VEGP internal events PRA model, room cooling is only modeled for the Emergency Diesel Generator (EDG) Rooms. The EDG room cooling is provided by plant systems other than ECWS. This assessment addresses the justification for reduction in redundancy of ECWS supported room cooling.

Methodology The approach used in the assessment of risk increase included the following considerations:

  • potential for creating a new initiating event (IE),
  • potential for an increase in the frequency of an existing IE(s), and
  • the impact on the consequence of an IE NewlE As documented in the VEGP PRA Model (PRA-BC-V-11-01, Appendix 2A, Modeling Effects of Loss of Room Cooling on VEGP Components), a number of VEGP specific room heat-up calculations have shown that room heat-up occurs over time and the room temperature can readily be reduced below equipment operating temperature limits by opening appropriate doors. Therefore, at the worst case, a loss of room cooling will result in a controlled plant manual shutdown. Crediting the "door opening" operator action to prevent an initiating event is limited to those cases where:
  • at least 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> are available prior to room heat up to a temperature at which damage might occur to supported equipment, and
  • the room temperature is found to be stabilized In the current PRA model documentation, only room R-B18, Unit 2 Train 2B "480V SWGR 2BB06", located in the Control Building, is assessed to require operator action (that is, to open the door). According to the VEGP room heat-up calculations, the available time to implement the compensatory measure of opening that door is 11.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />.

E1-7 to NL-11-1628 Basis for Proposed Change Thus, it was determined that no new IE will be created by the requested extension in completion time.

Impact on the Frequency of an Existing IE The ECWS maintains ambient air temperature in the ESF equipment rooms and switchgear rooms below the environmental qualification rating of the ESF equipment served by the system during all postulated accidents. The ECWS consists of two independent trains, each a closed loop system. Following a SI-inducing IE, both trains of the ECWS are automatically actuated; upon a loss-of-offsite-power (LOSP), the ECWS is manually actuated. During normal operation, the ECWS is the backup to the Normal Chilled Water System (NCWS),

which provides chilled water throughout the plant to all air cooling units which are required during normal plant operation. Because VEGP specific room heat-up calculations have shown that room heat-up occurs over time and the room temperature can readily be reduced below equipment operating temperature limits by opening doors, the impact of the proposed CT extension on the frequency of an existing IE is negligible.

Note, neither ECWS nor NCWS are required to support PRA-credited accident mitigating functions. However, NCWS can be used as a backup for ECWS in those locations served by both systems for all events that do not result in loss of offsite power. NCWS capacity is much larger than ECWS capacity. NCWS is operating and ECWS is in standby during normal power operations. If a reactor trip occurs, NCWS continues to operate unless there is a safety injection signal or LOSP. Therefore, during normal operation and after shutdown, NCWS is the primary source of chilled water. In case of a LOCA, the NCWS trips and the ECWS auto starts on a safety injection signal. However, NCWS could be used as a backup if it is manually restarted and normal power is available.

Impact on Consequences of Other IEs As stated above, the ECWS is credited to provide cooling following a SI-inducing initiating event or a LOSP event. Based on a detailed review of VEGP-specific room heat-up calculations and industry reference documents, it has been concluded that the ECWS supported systems will be able to perform their safety function within the PRA credited mission time (24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />). The basis for this conclusion was reached by using the industry reference documents to establish survivability and VEGP specific calculations to establish room heat up. Industry and VEGP specific reference documents used for establishing the basis for survivability include the following:

  • "Guidelines and Technical Bases for NUMARC Initiatives Addressing Station Blackout at Light Water Reactors," NUMARC 87-00 Rev.1, l'Juclear Management and Resource CounCil, Inc., 1991
  • "Equipment Operability During Station Blackout Events," NUREG/CR-4942, Sandia National Laboratories, 1987
  • "Equipment Qualification Test Report Long Term Component Aging Program," WCAP 8687 (VEGP document number: AX6AA10-00124), Westinghouse, 1987
  • "Equipment Qualification of Westinghouse NSSS Class 1 E Equipment," WCAP 8587, Westinghouse, 1987 E1-8 to NL-11-1628 Basis for Proposed Change The VEGP specific room heat-up evaluations includes the following:
  • "Room Heat Up Calculations," REA 95-VAA093, Southern l\Iuclear Operating Company, 1996
  • "Loss of HVAC," REA VG-2007, Southern Nuclear Operating Company, 1992
  • "VEGP 1 & 2 Room Temperature Heatup Calculation," GP-17289, Westinghouse, 2001 Room heat-up evaluations were performed for every room that contains PRA credited components.

For one room (R-B18, "480V SWGR 2BB06, 2BB07 and 2BBC"), located in the Control Building, the requirement for room cooling following an accident was screened out by crediting operator action to open the door. In this case, the available time to take the action was 11.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />.

It should be noted that the results of the Unit 1 heat-up calculations are used in this evaluation. Due to similarities in the room characteristics between the Unit 1 and Unit 2 rooms, the results of the Unit 1 heat-up calculations are judged to be applicable to the Unit 2 rooms.

Operator actions to open doors were only credited where the action would not be impacted by the post accident environmental condition (such as radiological concern). Also, the following should be noted:

  • Procedure (191 OO-C) provides guidance on establishing room cooling in an event of total loss of all AC power.
  • For non-LOSP initiating events, the NCWS is available to provide cooling to most rooms supported by the ECWS. The most likely use of the door-opening compensatory measure is an event of LOSP or during normal operation. There are no radiological concerns in either case.

Since the loss of ECWS does not result in an initiating event or impact any accident mitigating systems and, therefore, does not impact core damage, external events are discounted in the evaluation of the proposed extension of the ECWS CT.

Therefore, the impact of loss of ECWS on the consequences of any initiating event (due to internal hazards) is considered to be negligible.

Results and Conclusion The results of the risk evaluation indicate that the potential impact of the unavailability of the ECWS on the PRA figures of merit (CDF and LERF) is negligible because the PRA credited components can perform their intended function within the PRA mission time. Therefore, the ICCDP and ICLERP for the proposed change in the CT are well below the Regulatory Guide 1.177 acceptance criteria (the ICCDP and ICLERP are negligible).

E1-9 to NL-11-1628 Basis for Proposed Change Tier 2: Avoidance of Risk-Significant Plant Configurations The objective of the second tier, which is applicable to CT extensions, is to provide reasonable assurance that risk-significant plant equipment outage configurations will not occur when equipment is out of service. If risk-significant configurations do occur, then enhancements to the TS or procedures, such as limiting unavailability of backup systems, increased surveillance frequencies, or upgrading procedures or training, can be made that avoid, limit, or lessen the importance of these configurations.

Specifically, the following Tier 2 controls are implemented during the period of the proposed extended CT:

  • Increase reliability and availability of the NCWS

- No work will be performed in the U1 and U2 Low Voltage or High Voltage Switchyard that might result in a LOSP.

- No work will be performed on the NCWS components and their supporting components that would reduce system reliability.

  • Increase reliability and availability of the Train 2A of the ECWS

- Availability of the ECWS Train 2A is verified.

- No work will be performed on ECWS Train A components and their supporting components that would reduce system reliability.

  • Increase the reliability of providing cooling to the affected room.

- Contingency plans for propping open doors and placing temporary cooling (fans) in place if the normal chillers and the 2A essential chiller are lost.

- Minimize work on Unit 1 ECWS components that support the control room.

Tier 3: Risk-Informed Configuration Risk Management The objective of the third tier is to ensure that the risk impact of out-of-service equipment is evaluated prior to performing any maintenance activity. As stated in RG 1.177, "a viable program would be one that is able to uncover risk-significant plant equipment outage configurations as they evolve during real-time, normal plant operation." The third-tier requirement is an extension of the second-tier requirement, but addresses the limitation of not being able to identify all possible risk-significant plant configurations in the second-tier evaluation.

SNC has developed a process for online risk assessment and management. Adherence to the process and procedures ensures that the risk impact of equipment unavailability is appropriately evaluated both prior to performing any maintenance activity, and following an equipment failure or other internal or external event that impacts risk. Procedure NMP-OS-010, "Protected Train/Division and Protected Equipment Program", and Procedure 00354-C, "Maintenance Scheduling" provides guidance for managing safety function, probabilistic, and plant trip risks as required by 10 CFR 50.65(a)(4) of the Maintenance Rule. These procedures address risk management practices in the maintenance planning phase and maintenance execution (real time) phase for Modes 1 through 4. Appropriate consideration is given to equipment unavailability, operational activities such as testing, and weather conditions.

E1-10 to NL-11-1628 Basis for Proposed Change In general, risk from performing maintenance during power operation is minimized by:

  • Performing only those preventive and corrective maintenance items during power operation required to maintain the reliability of systems, structures, or components (SSCs).
  • Minimizing cumulative unavailability of safety-related and risk-significant SSCs by limiting the number of at-power maintenance outage windows per cycle per train/component.
  • Minimizing the total number of SSCs out of service at the same time.
  • Minimizing the risk of initiating plant transients (trips) that could challenge safety systems by implementing compensatory measures.
  • Avoiding higher risk combinations of out of service SSCs using PRA insights.
  • Maintaining defense-in-depth by avoiding combinations of out of service SSCs that are related to similar safety functions or that affect multiple safety functions.
  • Scheduling in train/bus windows to avoid removing equipment from different trains simultaneously.

In general, risk is managed by:

  • Evaluating plant trip risk activities or conditions and mitigating them by taking appropriate compensatory measures and/or ensuring defense-in-depth of safety systems that are challenged by a plant trip.
  • Evaluating and controlling risk based on probabilistic and key safety function defense-in depth evaluations.
  • Implementing compensatory measures and requirements for management authorization or notification for certain "high-risk" configurations.

Actions are taken and appropriate attention is given to configurations and situations commensurate with the level of risk. This occurs during both the planning and the real time (execution) phases.

The current practice for planned maintenance activities is for an assessment of the overall risk of the activity on plant safety (including benefits to system reliability and performance) to be performed and documented prior to scheduled work. In this assessment, consideration is given to plant and external conditions, the number of activities being performed concurrently, the potential for plant trips, and the availability of redundant trains.

Risk is evaluated, managed, and documented for all activities or conditions based on the current plant state:

  • Before any planned or emergent maintenance is to be performed.
  • As soon as possible when an emergent plant condition is discovered.
  • As soon as possible when an external or internal event or condition is recognized.

E1-11 to Nl-11-1628 Basis for Proposed Change Compensatory measures are implemented as necessary and if the risk assessment reveals unacceptable risk, a course of action is determined to restore degraded or failed safety functions and thereby reduce the probabilistic risk.

Compensatory Measures SNC commits (see Enclosure 4) to implementing compensatory measures as follows during the extended CT period required for the 180-month overhaul PM for the 2B essential chiller, including designation of the Unit 2 Train 2A ESF room coolers and ECWS as a "Protected Train." Procedure NMP-OS-010 defines the "Protected Train and Protected Equipment" process. The fundamental objective of the procedure is to enhance nuclear safety by ensuring continued availability of equipment necessary to maintain plant emergency response capability and prevent inadvertent plant trips, transients, or safety system challenges. This procedure provides guidance for management of the protected train and for posting protected equipment when redundant equipment is out of service. Additionally, operation or maintenance of protected plant equipment is limited or prohibited.

Protected train status means that activities such as corrective and preventative maintenance, system or component testing or activities in which human error could result in damage to or loss of protected equipment (for example, erecting scaffolding in the vicinity) are prohibited unless authorized by Operations management.

Unit 2 Train 2A ESF room coolers and ECWS equipment will be protected during this time period. Specifically, no elective or corrective maintenance, surveillance testing or any activity that could adversely affect the availability of the Train 2A equipment would be permitted, unless the activity will be required to ensure continued safe operation of the plant and such activity was approved by Operations management. Additionally, major components/locations associated with the ESF room coolers and ECWS will have signage placed to alert personnel that the equipment is "Protected." Signage locations will include both entrances to the room housing the Train 2A essential chiller and CREFS, the entrance to the Train 2A chiller power supply room, and the main control room handswitches for the Train 2A chiller and chilled water pump.

To maintain plant personnel awareness of the protected train, at a minimum, the protected train is identified on the plant morning report, in the Main Control Room, Maintenance Shop areas, HP Control Point and in the Work Release office. The protected train is also discussed at the beginning of shift briefings for each group.

Additional compensatory measures include maintaining the following equipment available (that is, no routine testing or maintenance activities will be performed):

  • High Voltage Switchyard -Offsite Source Feeds to Reserve Auxiliary Transformers. Work that does not challenge both feeders to offsite power will be permitted and managed as a high Operational Risk Awareness job.
  • Normal Chilled Water System (NCWS).

E1-12

Enclosure 1 to NL-11-1628 Basis for Proposed Change A contingency plan will be in place for monitoring temperature in the rooms listed below; propping open doors, as deemed necessary, per procedure 19100-C; and putting temporary cooling measures (fans) in place if the Train 2A ESF Room Coolers, Train 2A ECWS, or Train 2A and 2B NCW systems are out of service. It is expected that only in the case of loss of all HVAC (in the Control Building) will doors be opened and fans installed. On loss of the HVAC there would be no design airflow, hence the only airflow patterns (apart from natural convection) would be those established by the portable fans. In addition, there would be no driving force to introduce radioactivity into the control building, hence there would be no impediment to operator actions in the control building due to airborne radioactivity. Fans and the required extension cords are staged in the vicinity of these rooms. The fans will be positioned to draw air from the area outside these rooms and discharge into these rooms. The rooms whose doors have been identified to be propped open are as follows:

  • Control Bldg Room B18 - 480 Vac B Train SWitchgear Room
  • Control Bldg Room B31 - 125 Vdc D Train Switchgear Room
  • Control Bldg Room B36 - 125 Vdc B Train Switchgear Room
4. Regulatory Evaluation 4.1 Significant Hazards Consideration The proposed changes will provide a one-time revision to the Vogtle Electric Generating Plant (VEGP) Unit 2 Completion Time of TS 3.7.14, Condition A, to allow one inoperable Engineered Safety Features (ESF) Room Cooler and Safety-Related Chiller train for 9 days. The extended Completion Time will permit performance of the 180-month preventive maintenance of the Train 2B essential chiller while continuing plant operation. Also proposed is an editorial change to delete a note added as an emergency change to TS 3.7.14 per SNC letter NL-10-1609 dated August 18, 2010. That note was for a one-time use and is no longer needed.
1. Does the proposed license amendment involve a significant increase in the probability or consequences of an accident previously evaluated?

The proposed changes do not alter any plant equipment or operating practices in such a manner that the probability of an accident is increased. The proposed changes will not alter assumptions relative to the mitigation of an accident or transient event. Therefore, the proposed changes do not involve a Significant increase in the probability or consequences of an accident previously evaluated.

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

The proposed changes do not involve any physical alteration of the plant or significant change in the methods governing normal plant operation. Therefore, the proposed changes do not create the possibility of a new or different kind of accident from any accident previously evaluated .

E1-13 to NL-11-1628 Basis for Proposed Change

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

Based on the operability of the remaining ESF Room Cooler and Safety-Related Chiller Train 2A, the accident analysis assumptions continue to be met with enactment of the proposed changes. The system design and operation are not affected by the proposed changes. The safety analysis acceptance criteria are not altered by the proposed changes. Finally, the proposed compensatory measures will provide further assurance that no significant reduction in a safety margin will occur.

The proposed changes provide reasonable assurance that the ESF Room Cooler and Safety-Related Chiller system will continue to perform its intended safety function.

Therefore, the proposed changes do not involve a significant reduction in a margin of safety.

Based on the above, Southern Nuclear Operating Company concludes that the proposed changes present no significant hazards consideration under the standards set forth in 10 CFR 50.92(c), and, accordingly, a finding of "no significant hazards consideration" is justified.

4.2 Applicable RegUlatory ReqUirements/Criteria

  • General Design Criterion 2 of Appendix A to 10 CFR 50, General Design Criteria for Nuclear Power Plants, requires that nuclear power plant structures, systems, and components important to safety be designed to withstand the effects of natural phenomena such as earthquakes, tornadoes, hurricanes, floods, tsunami, and seiches without loss of capability to perform their safety functions.

For VEGP, the essential chiller, chilled water pump, and piping are designed in accordance with Seismic Category 1 requirements.

  • 10 CFR 50.36(c)(2)(ii): A technical specification limiting condition for operation of a nuclear reactor must be established for each item meeting one or more of the following criteria:

Criterion 4: A structure, system, or component which operating experience or probabilistic risk assessment has shown to be significant to public health and safety.

For VEGP, TS 3.7.14 limiting condition for operation has been established for the ESF room cooler and safety-related chiller system.

4.3 Conclusion The proposed changes will provide a one-time revision to the VEGP Unit 2 Completion Time of TS 3.7.14, Condition A to allow an inoperable ESF Room Cooler and Safety Related Chiller train for 9 days. The extended Completion Time will permit completion of the 180-month preventive maintenance of the Train 2B essential chiller while continuing E1-14

Enclosure 1 to NL-11-1628 Basis for Proposed Change plant operation. Also proposed is an editorial change to delete a note added as an emergency change to TS 3.7.14 per SNC letter NL-10-1609 dated August 18, 2010. That note was for a one-time use and is no longer needed.

The Plant Review Board reviewed the proposed change to the Technical Specifications and concluded that it does not involve a significant hazard consideration and will not endanger the health and safety of the public.

5. Environmental Consideration The proposed changes qualifies for categorical exclusion from an environmental assessment as set forth in 10 CFR 51.22(c)(9). Therefore, no environmental impact statement or environmental assessment is needed in connection with the approval of the proposed changes.

This amendment request meets the eligibility criteria for categorical exclusion set forth in 10 CFR 51.22(c)(9) as follows:

(i) The amendment involves no significant hazards consideration.

As described above, the proposed changes involve no significant hazards consideration.

(ii) There is no significant change in the types or significant increase in the amounts of any effluents that may be released offsite.

The proposed changes do not involve the installation of any new equipment or the modification of any equipment that may affect the types or amounts of effluents that may be released offsite. Therefore, there is no significant change in the types or significant increase in the amounts of any effluents that may be released offsite.

(iii) There is no significant increase in individual or cumulative occupation radiation exposure.

The proposed changes do not involve plant physical changes or introduce any new mode of plant operation. Therefore, there is no significant increase in individual or cumulative occupational radiation exposure.

Based on the above, SNC concludes that the proposed changes meet the criteria specified in 10 CFR 51.22(b) for a categorical exclusion from the requirements of 10 CFR 51.22(c)(9) relative to requiring a specific environmental assessment by the Commission.

6. References
1. VEGP FSAR, Revision 17, 08/31/11 Update
2. VEGP Units 1 and 2 Technical Specifications, Amendments 161 and 143 respectively, Section 3.7.9
3. VEGP Units 1 and 2 Environmental Protection Plan, Amendments 97 and 75 respectively E1-15 to NL-11-1628 Basis for Proposed Change
4. NUREG-1137 "Safety Evaluation Report related to the operation of Vogtle Electric Generating Plant, Units 1 and 2" dated June 1985 5 . . "Room Heat Up Calculations," REA 95-VAA093, Southern Nuclear Operating Company, 1996
6. "Loss of HVAC," REA VG-2007, Southern Nuclear Operating Company, 1992
7. "VEGP 1 & 2 Room Temperature Heatup Calculation," GP-17289, Westinghouse, 2001
8. Vogtle procedure 191 OO-C "ECA-O.O Loss of All AC Power" Revision 37
9. Vogtle letter NL-1 0-1609 "Vogtle Electric Generating Plant Unit 2 Emergency Technical Specification Revision Request for TS 3.7.14 Engineered Safety Features (ESF) Room Cooler and Safety-Related Chiller System" dated August 18, 2010
10. Vogtle letter NL-10-1623 "Vogtle Electric Generating Plant Unit 2 Emergency Technical Specification Revision Request for TS 3.7.14 Engineered Safety Features (ESF) Room Cooler and Safety-Related Chiller System Response to Requests for Additional Information" dated August 18, 2010
11. Vogtle letter NL-11-1297 "Vogtle Electric Generating Plant -Units 1 and 2 Methods to be used in the Implementation of Risk-Informed Technical Specifications Initiative 4b" dated September 27, 2011 E1-16

Vogtle Electric Generating Plant Unit 2 Technical Specification Revision Request for TS 3.7.14 Engineered Safety Features (ESF)

Room Cooler and Safety-Related Chiller System Enclosure 2 Marked-up Technical Specifications Page

ESF Room Cooler and Safety-Related Chiller System 3.7.14 3.7 PLANT SYSTEMS 3.7.14 Engineered Safety Features (ESF) Room Cooler and Safety Related Chiller System LCO 3.7.14 Two ESF Room Cooler and Safety-Related Chiller trains shall be OPERABLE.

NOTE----------------------------------------------

One Safety-Related Chiller train may be removed from service for

$ 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> under administrative controls for surveillance testing of the other Safety-Related Chiller train.

APPLICABILITY: MODES 1, 2, 3, and 4.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One ESF room cooler A.1 Restore the ESF room 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />s*

and safety-related chiller cooler and safety-related train inoperable. chiller train to OPERABLE status.

B. Required Action and B.1 Be in MODE 3. 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> Associated Completion Time not met. AND B.2 Be in MODE 5. 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />

  • For the VEGP Unit 2 entry into Technical Specifications 3.7.14 Condition A, the 2B ESF room cooler and safety-related chiller train may be inoperable for an overhaul preventive maintenance during a period not to exceed 9 days on a one-time basis, prior to the refueling outage scheduled to begin on March 10, 2013.

Vogtle Units 1 and 2 3.7.14-1 Amendment No. 96 (Unit 1)

Amendment No. 139 (Unit 2)

Vogtle Electric Generating Plant Unit 2 Technical Specification Revision Request for TS 3.7.14 Engineered Safety Features (ESF)

Room Cooler and Safety-Related Chiller System Enclosure 3 Clean-Typed Technical Specifications Page

ESF Room Cooler and Safety-Related Chiller System 3.7.14 3.7 PLANT SYSTEMS 3.7.14 Engineered Safety Features (ESF) Room Cooler and Safety Related Chiller System LCO 3.7.14 Two ESF Room Cooler and Safety-Related Chiller trains shall be OPERABLE.

NOTE-------------------~---------------------------

One Safety-Related Chiller train may be removed from service for

~ 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> under administrative controls for surveillance testing of the other Safety-Related Chiller train.

APPLICABILITY: MODES 1, 2, 3, and 4.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One ESF room cooler A.1 Restore the ESF room 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />s*

and safety-related chiller cooler and safety-related train inoperable. chiller train to OPERABLE status.

B. Required Action and B.1 Be in MODE 3. 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> Associated Completion Time not met. AND B.2 Be in MODE 5. 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br />

. maintenance during a period not to exceed 9 days on a one-time baSiS, prior to the refueling outage scheduled to begin on March 10, 2013.

Vogtle Units 1 and 2 3.7.14-1 Amendment No. 96 (Unit 1)

Amendment No. (Unit 2)

Vogtle Electric Generating Plant Unit 2 Technical Specification Revision Request for TS 3.7.14 Engineered Safety Features (ESF)

Room Cooler and Safety-Related Chiller System Enclosure 4 Commitment Table to NL-11-1628 Commitment Table List of Regulatory Commitments The following table identifies the regulatory commitments in this document. Any other statements in this submittal represent intended or planned actions. Such statements are provided for information purposes and are not considered to be regulatory commitments.

One-Time Regulatory Commitments Completion Event Action The Unit 2 Train A ESF Room Cooler and Safety-Exit of TS 3.7.14 Related Chiller System will be operated as a X Condition A Protected Train per procedure NMP-OS-010.

The Unit 1 low voltage switchyards and the Unit 2 low voltage switchyards will be maintained Exit of TS 3.7.14 X

available (that is, no routine testing or maintenance Condition A activities will be performed).

High voltage switchyards will be maintained available (that is, no routine testing or maintenance activities will be performed) with the exception of Exit of TS 3.7.14 work activities which do not challenge both feeders X Condition A from offsite power sources will be permitted and managed as a high Operational Risk Awareness job.

The Unit 2 Train A and Train B Emergency Diesel Generators will be maintained available (that is, no Exit of TS 3.7.14 X

routine testing or maintenance activities will be Condition A performed).

The Normal Chilled Water System will be Exit of TS 3.7.14 maintained available (that is, no routine testing or X Condition A maintenance activities will be performed).

The Unit 1 Essential Chilled Water System and Unit 1 CREFS will be maintained available to support Exit of TS 3.7.14 X

control room cooling (that is, no routine testing or Condition A maintenance activities will be performed).

A contingency plan will be in place for propping open doors per procedure 191 OO-C and putting temporary cooling measures (fans) in place if the Exit of TS 3.7.14 X

Train 2A ESF room coolers, Train 2A safety-related Condition A chiller system, and normal chilled water system are out of service.

E4-1

Vogtle Electric Generating Plant Unit 2 Technical Specification Revision Request for TS 3.7.14 Engineered Safety Features (ESF)

Room Cooler and Safety-Related Chiller System Enclosure 5 Discussion of Probabilistic Risk Analysis Capability to NL-11-1628 Discussion of Probabilistic Risk Analysis Capability PRA Capability SNC employs a multi-faceted approach to establishing and maintaining the technical adequacy and plant fidelity of the PRA models for all operating SNC nuclear generation sites. This approach includes both a proceduralized PRA maintenance and update process, and the use of self-assessments and independent peer reviews. The following information describes this approach as it applies to the VEGP PRA.

Technical Adequacy of VEGP PRA Model The SNC risk management process ensures that the applicable PRA model remains an accurate reflection of the as-built and as-operated units. The SNC risk management process also delineates the responsibilities and gUidelines for updating the full power internal events PRA models at all operating SNC nuclear generation sites. The overall SNC risk management program defines the process for implementing regularly scheduled and interim PRA model updates, for tracking issues identified as potentially affecting the PRA models (e.g., due to changes in the plant, errors or limitations identified in the model, industry operational experience), and for controlling the model and associated computer files. To ensure that the current PRA model remains an accurate reflection of the as-built, as operated plant, the VEGP PRA model has been updated according to the requirements defined in the SNC risk management process:

  • Modifications to the physical plant (Le. those potentially affecting the Base Line PRA (BL PRA) models, calculated core damage frequencies (CDFs), or large early release frequencies (LERFs) to a significant degree) shall be reviewed to determine the scope and necessity of a revision to the baseline model within six months following the Unit 2 refueling outage or a specific major plant modification occurring outside a refueling outage. The BL-PRAs should be updated as necessary in accordance with a schedule approved by the PRA Manager following the scoping review. Upon completion of the lead Unit's BL-PRA, the other Unit's BL-PRA will be regenerated by modification of the updated BL-PRAs to account for Unit differences which significantly impact the results.
  • Modifications to plant procedures and Technical Specifications shall be reviewed annually for changes which are of statistical significance to the results of the BL-PRA and those changes documented. Reliability data, failure data, initiating events frequency data, human reliability data, and other such PRA inputs shall be reviewed approximately every three years for statistical significance to the results of the BL-PRAs. Following the tri annual review, the BL-PRAs shall be updated to account for the statistically significant changes to these two categories of PRA inputs in accordance with an approved schedule.
  • BL-PRAs shall be updated to reflect germane changes in methodology, phenomenology, and regulation as judged to be prudent by the PRA Model Lead or as required by regulation.

In addition to these activities, SNC risk management procedures provide the guidance for particular risk management and PRA quality and maintenance activities. This guidance includes:

  • Documentation of the PRA model, PRA products, and bases documents.

ES-1 to NL-11-1628 Discussion of Probabilistic Risk Analysis Capability

  • The approach for controlling electronic storage of Risk Management (RM) products including PRA update information, PRA models, and PRA applications.
  • Guidelines for updating the full power, internal events PRA models for SNC nuclear generation sites.
  • Guidance for use of quantitative and qualitative risk models in support of the during power operation Work Control Process Program for risk evaluations for maintenance tasks (corrective maintenance, preventive maintenance, minor maintenance, surveillance tests and modifications) on systems, structures, and components(SSCs) within the scope of the Maintenance Rule (10 CFR 50.65 (a)(4)).

In accordance with this guidance, regularly scheduled PRA model updates nominally occur on an approximate three-year cycle; however, longer intervals may be justified if it can be shown that the PRA continues to adequately represent the as-built, as-operated plant. Table 1 shows a brief history of the major VEGP PRA model updates.

E5-2 to NL-11-1628 Discussion of Probabilistic Risk Analysis Capability Table 1: History of the Major VEGP PRA Model Updates Model Document No. Scope Updated Items CDF and LERF (/yr)

IPE WCAP-13553 At-power, internal and The original CDF: 4.9E-05 (Westinghouse report) by external, Level 1 arid Level 2, LERF: 1.78E-06 Westinghouse and SNC, 11/1992 Rev. 0 SAIC prepared reports At-power, internal, CDF and Conversion from a large Event CDF: 3.62E-05 3/1998 LERF Tree/small Fault Tree approach to a LERF: 1.72E-06 small Event Tree/large Fault tree approach (linked fault tree model The CDF reduction was method) . mainly due to changes, such as removal of PRA software changed from unrealistic SBO scenarios, WESQT/GRAFTER (Westinghouse addition of more realistic Event Tree and Fault tree software) assumptions regarding the to CAFTA. effect of loss of room cooling and removal of a

'guaranteed failure' assumption made during the IPE for event CON (operator action to depressurize one SG to cause feed flow from the condensate pumps if AFW failed).

Rev. 1 PSA-V-99-002 by SNC, At-power, CDF and LERF Enhanced the treatment of operator CDF: 3.702E-05 9/1999 action dependency, removal of LERF: 2.290E-06 circular logic, and minor corrections /

improvements. -- -

E5-3 to NL-11-1628 Discussion of Probabilistic Risk Analysis Capability Table 1: History of the Major VEGP PRA Model Updates Model Document No. Scope Updated Items CDF and LERF (/yr)

Rev. 2 PSA-V-99-012 by SNC, At-power, CDF and LERF Update of initiating event CDF: 1.48E-OS 1/2000 frequencies, component failure LERF: 1.1SE-OB data, and maintenance unavailabilities using plant There was a considerable reduction specific data collected through in CDF mainly due to reduction in the end of 1998. the transient event frequency. The sum of frequencies of eight transient Incorporated plant changes. subcategories was reduced from 4.04/yr to 2.B4/yr after the data update. Also, items updated during revision Oa, ~b, and Oc, especially the crediting of the plant Wilson switchyard for a back up AC power source, contributed to the reduction in CDF.

The reduction in LERF was mainly due to reduced failure probabilities of some of the components, especially NSCW pumps , which have a significant contribution to the LERF after the Bayesian update of failure data using VEGP specific failure data.

E5-4 to NL-11-1628 Discussion of Probabilistic Risk Analysis Capability Table 1: History of the Major VEGP PRA Model Updates Model Document No. Scope Updated Items CDF and LERF (/yr)

Rev.2a PSA-V-00-003 by SNC, At-power, CDF and LERF Addition of RCP seal LOCA CDF: 2.40E-05 7/2000 failure modes which were newly LERF: 7.34E-07 identified by the Westinghouse Owners Group (WOG), changes CDF increase was due to the new in success criteria for Steam RCP seal LOCA failure modes.

Generator Tube Rupture LERF decrease was due to changes (SGTR), and minor changes to in success criteria for SGTR.

facilitate Maintenance Rule and MOV/AOV risk ranking.

Rev.2b PSA-V-00-020 by SNC, At-power, CDF and LERF Minor improvement in recovery CDF: 2.3SE-05 11/2000 tree for recovery analysis. LERF: 7.34E-07 No significant changes in CDF and LERF Rev.2c PSA-V-00-030 by SNC, At-power, CDF and LERF Peer reviewed model by the CDF: 1.602E-05 11/2001 WOG PRA peer review team. LERF: 7.S02E-OS Revised the LERF model based The CDF decrease was mainly due on the new WOG LERF to a decrease in LOCA frequencies modeling guidelines. Updated after an update of initiating the initiating event frequencies frequencies using NUREG/CR-5750 using the more recent generic data.

data source (NUREG/CR-5750).

The decrease in LERF was due to Some SGTR scenarios were the removal of some SGTR removed from the LERF scenarios for the LERF model.

scenarios and minor changes were made to facilitate RIS_B analysis. Removed circular logic I in normal charging pump fault trees. I ES-S to NL-11-1628 Discussion of Probabilistic Risk Analysis Capability Table 1: History of the Major VEGP PRA Model Updates Model Document No. Scope Updated Items CDF and LERF (/yr)

Rev. 3 PRA-BC-V-06-001 by At-power, CDF and LERF This is the most extensive CDF: 1.28E-05 SNC, 2/2006 upgrade of the VEGP PRA LERF: 1.10E-O?

model since the IPE.

The CDF changes were due to All level 1 PRA tasks, from the combined effects of many changes selection and grouping of during revision 3.

initiating events to the final quantification were practically re The main cause of the LERF done. increase was the regrouping of all of the SGTR sequences back into the Resolved all Westinghouse containment bypass scenarios, and Owners Group PRA peer review the removal of the credit for B Facts and Observations mitigating systems for some (F&Os). There were no A F&Os. Interfacing Systems LOCA scenarios (as resolution of peer review ,

findings). I ES-6 to NL-11-1628 Discussion of Probabilistic Risk Analysis Capability Table 1: History of the Major VEGP PRA Model Updates Model Document No. Scope Updated Items CDF and LERF (lyr)

VEGPL2UP P0293060001-2707 At-power, internal, CDF Based on the Rev.3 level 1 PRA CDF: 1.552E-05 model (ERIN report) by SNC and full level 2 logic. This model was used for 1.529E-05 (after treating and ERIN, 11/2006 the Severe Accident success terms).

Management Alternative LERF: 1.B19E-07 Analysis for the VEGP license renewal which was submitted in The increase in CDF (before treating 2007. success terms) from revision 3 to VEGPL2UP model was due to the Upgraded the full level 2 PRA correction of a RCP seal LOCA model, based on WCAP-16341 probability from WCAP-16141.

P guidelines which aim for producing an ASME PRA The above LERF value is the sum of capability category II LERF four LERF release categories:

model. LERF-BYPASS, LERF-ISO, LERF CFE, and LERF-SGTR.

Incorporated success terms in level 1 and 2 logic. Corrected an error in the level 1 PRA failure data.

Rev. 4 PRA-BC-V-07-003 At-power, internal, CDF, Completed the following: CDF: mean = 1.40E-05, error factor and full level 2.

  • Performed pre-initiator HFE = 1.B Originally prepared in screening. LERF: mean = 4.96E-OB, error April 2009 for RG 1.200
  • Updated initiating frequency factor = 3.1 R 1 peer review against and component failure data. LERF reduction due to correction of ASME PRA standard in
  • Performed internal flooding wrong SG tube condition used in the May 2009. PRA. previous model. Also, use of new
  • Updated system notebooks. generiC initiating event frequency Rev. 4 was reissued
  • Performed Uncertainty based on new generic data base after resolving all "SR Analysis considering the state of (NUREG/CR-692B) which is almost I Not Met" Finding and knowledge correlation. an order of magnitude higher than Observations (total 3). the previous generic value. I ES-7 to NL-11-1628 Discussion of Probabilistic Risk Analysis Capability Table 1: History of the Major VEGP PRA Model Updates Model Document No. Scope Updated Items CDF and LERF (lyr)

Rev. 4.1 PRA-BC-V-11-001, by At-power, internal, CDF, Updated Grid Centered Loss of CDF: mean = 1.20E-05, error factor SNC and full level 2. Offsite Power events and 2.10 Service Water Pump(s) data. LERF: mean = 5.32E-08, error factor 3.45 CDF reduction was mainly due to data changes in conservative scenarios for Grid Centered Loss of Offsite Power. --

E5-8 to NL-11-1628 Discussion of Probabilistic Risk Analysis (PRA) Capability Consistency with Applicable ASME PRA Standard Requirements Previous peer review and Self Assessment for VEGP PRA Model In addition to independent internal and external review during each VEGP PRA model development and update, several assessments of the technical capability have been made before the PWR Owners Group (PWROG) peer review against the ASME PRA Standard and R.G. 1.200, Revision 1 in May of 2009. Listed below are the previous assessments for VEGP PRA:

  • An independent PRA peer review was conducted under the auspices of the Westinghouse Owners Group (WOG) in December 2001, following the Industry PRA Peer Review process. This peer review included an assessment of the PRA model maintenance and update process. This assessment did not identify any "A" Facts &

Observations (F&Os). All "8" F&Os from the 2001 Industry PRA Peer Review for VEGP PRA were addressed in VEGP PRA model Revision 3.

  • During 2005, the VEGP PRA model results were evaluated in the WOG PRA cross comparisons study performed in support of implementation of the mitigating systems performance indicator (MSPI) process. Results of this cross-comparison are presented in WCAP-16464, Westinghouse Owner's Group Mitigating Systems Performance Index (MSPI) Cross Comparison. The PRA Cross Comparison Candidate Outlier Status is described in section 3.4 of VEGP MSPI base document. Noted in this document was the fact that, after allowing for plant-specific features, there are no MSPI cross-comparison outliers for VEGP PRA.
  • In 2006, a gap analysis was performed against the available versions of the ASME PRA Standard and Regulatory Guide 1.200, Revision 0 (2003 trial version).
  • In 2008, VEGP PRA model (draft Revision 4) was bench marked with three Westinghouse PWRs (Comanche Peak, Callaway, Wolf Creek) as a part of MSPI margin study. The benchmarking concluded that there were no significant issues in the VEGP PRA model which would impact MSPI calculations.

RG 1.200 PRA Peer Review for VEGP PRA Model against ASME PRA Standard Requirements The VEGP PRA model for internal events (including internal flooding) at power was updated to Revision 4 early in 2009 to close the gaps from the 2006 self-assessment, to meet the ASME PRA Standard supporting requirements, and to represent the as-built as-operated plant.

In May of 2009, the VEGP PRA model Revision 4 was reviewed per RG 1.200 Revision 1 against ASME PRA Standard Requirements. A summary of this peer review is provided below:

The ASME PRA Standard contains a total of 327 numbered supporting requirements (SRs) in nine technical elements and the configuration control element. Eleven of the SRs represent deleted requirements (IE-A8, IE-A9, SC-A3, SY-A9, SY-89, HR-G8, IF-A2, IF-S4, IF-D2, IF-E2, and QU-D2) and 20 were determined to be not applicable to the VEGP PRA. Among the 296 applicable SRs, 99% of the SRs met Capability Category II or higher as follows:

E5-9 to NL-11-1628 Discussion of Probabilistic Risk Analysis (PRA) Capability Capability Category Met  % of total applicable No. of SRs SRs CC-II111111 (or SR Met) 210 70.9%

CC-I 0 0%

CC-II 38 12.8%

CC-III 7 2.4%

CC-II11 14 4.7%

CC-IIIIII 24 8.1%

SR Not Met 3 1.0%

SR (CC-III1/11 I) Met 296 100%

Three SRs were judged to be not met. These are HR-G6, QU-03, and LE-GS. HR-G6 was not met because the reasonableness check of Human Reliability Analyses (HRA) was done for the previous revision of the PRA and not the latest revision. QU-03 was not met because the SR requires the PRA results be compared with those from similar plants. The VEGP PRA report cites the MSPI benchmark report as evidence of meeting this requirement, which is an outdated comparison. LE-GS was not met because the limitation of the LERF calculations that could impact risk-informed applications was not identified.

Resolution of Findings from RG 1.200 PRA Peer Review Table 2 shows details of the three "SR Not Met" findings and resolutions after the peer review.

As shown in Table 2, the three not met SRs have been resolved.

ES-10 to Nl-11-1628 Discussion of Probabilistic Risk Analysis (PRA) Capability Table 2: Resolution of the VEGP PRA Peer Review F&Os associated three liSA not Met" SRs Review F&O# Level Resolution The Status of Resolution by SNC Element HR-G6 HR-G6 (SR Finding Check of consistency and Reasonableness check for all 01 not met CC- review for reasonableness HRAs for Revision 4 model was 1111/111) is missing in the Aev. 4 re-performed . All HRAs have updated HRA draft and the been determined to be reasonable prior revision document or have been appropriately information related to these revised.

items is not appropriate to use in light of the updates performed and changes to the results. Section 8 includes a table of HFEs and HEPs but does not include HEP reasonableness check, as is documented in Section 8.3 of the November 2005 HRA update of Revision 3.

E5-11 to NL-11-1628 Discussion of Probabilistic Risk Analysis (PRA) Capability Table 2: Resolution of the VEGP PRA Peer Review F&Os associated three "SR not Met" SRs Review F&O# Level Resolution The Status of Resolution by SNC Element QU-03 QU-03 (SR Finding Reviewer asked the VEGP In order to resolve the F&O, a new 01 CC-II Not Met) Staff to provide evidence of comparison study was performed comparison of the VEGP by comparing VEGP PRA results results to those from similar with two PWR PRAs (Callaway plants. The benchmark and Wolf Creek) which are report for MSPI was considered relatively similar to presented as evidence of VEGP . In addition to the comparison. Reviewer comparison of PRA reports, a plant concluded that the report is visit was performed to identify not sufficient evidence for more details of Callaway systems demonstrating compliance and PRA modeling .

with this SA.

The comparison showed that all three plants have LOSP/Station Black Out as the most dominant contributors which indicate that the VEGP PRA results are not an outlier as compared to similar PWRs. Oifferences in the dominant CDF contributors were investigated and it was found that these differences are due to differences in details of system configuration, operation and physical barriers for internal flooding, and in the sources for generic initiating events frequency data (VEGP PRA used the latest generic initiating frequency and failure data along with VEGP specific experience data for its data update).

Therefore, this F&O is resolved.

ES-12 to NL-11-1628 Discussion of Probabilistic Risk Analysis (PRA) Capability Table 2: Resolution of the VEGP PRA Peer Review F&Os associated three "SA not Met" SRs Review F&O# Level Resolution . The Status of Resolution by SNC Element LE-G5-01 LE-G5 (SR Finding Limitations in the LERF A comparison of VEGP LERF Not Met CC- analysis that would impact scenarios with those in Table 1111/111) applications are not 4.5.9.3 of the ASME PAA standard identified. LERF analysis revealed that the VEGP PRA documentation is incomplete included more potential LERF because limitations in the scenarios than as required for a LERF analysis that would large dry containment plant in the impact applications, as ASME PRA standard.

required by SR LE-G5, are not identified. The LERF scenarios modeled in VEGP PRA included containment bypass core damage scenarios (steam generator tube rupture and Interfacing systems LOCA),

thermal or pressure induced steam generator tube rupture after core damage, containment isolation failure with core damage, and various early containment failure modes.

Therefore, this F&O is resolved.

E5-13

Vogtle Electric Generating Plant Unit 2 Technical Specification Revision Request for TS 3.7.14 Engineered Safety Features (ESF)

Room Cooler and Safety-Related Chiller System Enclosure 6 ESF Room Coolers Served by Train 28 Safety-Related Chiller System to NL-11-1628 ESF Room Coolers Served by Train B Safety-Related Chiller System Engineered Safety Features (ESF) Room Coolers Served by Unit 2 Train 28 Safety-Related Chiller System Served By Served By ESF Room Cooler Room Number Area Served ECW NCW 2-1531-N7 -002-000 Main Control Room Main Control Room (Common to Units 1 and 2) Yes No*

A15, A24, A79, B17, B18, B28, Control Building Battery Rooms, Motor Control Center Room, 2-1532-A7-002-000 Yes Yes B31, B32, B36, Switchgear Rooms, and Shutdown Room B37, 2-1539-A7-002-000 223 Control Building Auxiliary Isolating Relay Room Yes No Auxiliary Building Electrical Switchgear and Motor Control Center 2-1555-A7 -002-000 223 Yes Yes Room Auxiliary Building Electrical Switchgear and Motor Control Center 2-1555-A 7-004-000 B122 Yes Yes Room Auxiliary Building Electrical Switchgear and Motor Control Center 2-1,555-A7 -006-000 147 Yes Yes Room 2-1555-A7-008-000 D121 Auxiliary Building Residual Heat Removal Pump Room Yes Yes 2-1555-A7-010-000 D04 Auxiliary Building Containment Spray Pump Room Yes No 2-1555-A7-012-000 A96 Auxiliary Building Component Cooling Water Pumps Room Yes No Auxiliary Building Chemical and Volume Control System Charging 2-1555-A7-014-000 C17 Yes Yes Pump Room 2-1555-A7-016-000 B117 Auxiliary Building Safety Injection System Pump Room Yes No 2-1555-A7-018-000 A04 Fuel Handling Building Yes Yes I No I 2-1561-E7 -001-000 Series of Rooms Piping Penetration Area Yes (served by I NSCW)

  • Normal cooling is provided by normal air handling units (A-1531-A7-001 and Legend A-1531-A7-002) served by NCW. ECW Essential Chilled Water NCW Normal Chilled Water NSCW - Nuclear Service Cooling Water E6-1
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