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Attachment 4

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North Anna Power Station Units 1 and 2| Emergency Diesel Generator |

Preventive Maintenance inspection Outage

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PROBABILISTIC SAFETY ASSESSMENT

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August 1995

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VIRGINIA ELECTRIC AND POWER COMPANY

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95090B0288 950901PDR ADOCK 05000338P PDR

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TABLE OF CONTENTS

1.0 INTRODUCTION 4.......................................

2.0 BACKGROUND INFORMATION 4'.............................

2.1 Emergency Diesel Generator . . . . . . . . . . . . . . . . . . . . . . . . . . . 52.2 Emergency Electrical Power System 7.....................

2.3 Alterna te A.C. Die sel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8-

3.0 PSA A N ALYSI S . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 133.1 Comparison to IPE model . . . . . . . . . . . . . . . . . . . . . . . . . . . . 133.2 Revised EDG Unavailability Data . . . . . . . . . . . . . . . . . . . . . . . 16

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2 3.3 A A C DG TM . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 173.4 AAC DG Base Case . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

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3.5 Extended EDG Unavailability . . . . . . . . . . . . . . . . . . . . . . . . . . . 19'

3.6 BOUN DING Model . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19' 3.7 Results ........................................19

5 4.0 ACCEPTABLE RISK INCREASES . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

5.0 IMPLEMENTATION REQUIREMENTS . . . . . . . . . . . . . . . . . . . . . . . . . 27.

6.0 CO N C LU SI O N S . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31.

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APPENDIX A: Fault Trees

APPENDIX B: Event Trees

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1.0 INTRODUCTION

1 This report was prepared to document the feasibility of a 14-day outage on-line4 (Modes 1,2,'3 and 4) for preventive maintenance and inspection of each emergency

diesel generator (EDG) once every 18 months. The alternate A.C. diesel generator ,

j (AAC DG) recently installed at North Anna is assumed to be operable during the: performance of this EDG preventive maintenance and inspection. It has been

determined that the increase in risk associated with performance of the 18-month ''

; diesel preventive maintenance and inspection on-line is acceptably small. Based oni this conclusion, a request for revised North Anna Power Station Technical

Specifications associated with EDG outage time is being proposed. This report is9

being prepared to serve as an attachment to the licensing package.!

Section 2 presents background information on the reason for the request and asummary description of the relevant systems including a description of the AAC DG. -

Section 3 contains a discussion of the PSA analysis performed. Section 4 presents:

i a discussion of acceptable risk increases, implementation requirements are providedj in Section 5. Section 6 contains conclusions. References are provided as footnotes.:

2.0 BACKGROUND INFORMATION

The EDGs installed at North Anna Power Station were manufactured by Fairbanks-Morse. The manufacturer recommends that an extensive inspection of these diesels .

: be performed every 18 months. Currently, this maintenance is performed during !

| shutdown conditions as required by Technical Specifications. Because the inspectionsrequire at least ten days to complete, a significant burden is placed on themaintenance crews to perform this work along with the many other tasks that mustbe performed during an outage.,

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| Virginia Power has determined that the substantial benefits of performing thisi maintenance on-line justify the negligible increase in risk for at-power conditions

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to installation of the AAC DG,>

to improved maintenance quality resulting from focused resources on thej >

j EDG maintenance, andto less EDG unavailability during shutdown (i.e., Modes 5 and 6) which| >

lowers shutdown risk.The following sections provide a description of the generators and the powerdistribution system. This background information is important because it provides an

: understanding of the various sources of A.C. power and of the path to the emergencyI bus.i

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2.1 Emergency Diesel Generator

The Emergency Generator (EG) System provides a reliable source of emergencyelectric power to Engineered Safeguards Features (ESFs) and other essential loads in

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the event of a Loss of Off-site Power (LOOP)'. The EG System consists of two 100-percent capacity Emergency Diesel Generator (EDG) sets in each unit. Each EDGindependently powers a train of safety-related equipment, thereby providingredundancy in the event of loss of an EDG. Each EDG in a unit will automatically startwhen a safety injection signal from its associated train is present. Each EDG in a unitwill automatically start with a pre-set time delay upon sensing either undervoltage ordegraded voltage on its associated 4kV bus or an improper 4kV supply breaker lineup.Then, an EDG output breaker closes, and loads connect sequentially to the emergencybus if the residual voltage on the bus is less than 30 percent, a degraded orundervoltage exists, the 4kV buses are aligned properly, the EDG volts are greaterthan 95 percent, and the EDG output breaker lock-out and EDG differential breakerrelay are reset. Each EDG is initiated automatically or manually and consists of adiesel engine, governor, generator with excitation system, controls, battery andcharger, and the following subsystems: starting air, fuel oil, scavenging air andexhaust, lubricating oi!, Jacket cooling, and air cooling.

The diesel engine provides sufficient mechanical power to drive a generator with a2,000 hr/yr rating of not less than 3,000kW, both mounted on a sub-base. Thegovernor is furnished with an adjustable speed droop, load limit, and remote speedcontrol for 125V de operation

The EG System may be operated from the Main Control Room or from the DieselGenerator Rooms. Control circuits are provided for local and remote operation of theengine, generator and generator output breakers. The engine initiation signals areprovided from the Emergency Electrical Power (EE) System (under/ degraded voltage)and the Reactor Protection System (RPS) safety injection signal.

The generator and exciter provide a 2000 hr/yr capacity of 3,000 Kw at 4160V,60cycles. The generator uses a brushless exciter and rectifier assembly to provideexcitation to the main generator field. Space heaters are provided for insulationprotection.

The EDG battery and battery charger provide power for flashing the generator field,powering the dc fuel oil pump, powering the speed control motor, operating the airstarting solenoids, and providing power for EDG control circuits voltage regulation and !protective relays.'

8The information in this section is taken from the SDBD ,

document " Emergency Diesel Generator System, North Anna PowerStation," SDBD-NAPS-EG, Rev. 1, Section 3.1, 12/31/93

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The starting air subsystem for each EDG consists of two independent, separate trainsof equipment and piping that deliver compressed air to the diesel engine. Either trainis capable of starting the engine without outside electric power.

Each starting air train has an air receiver (tank) that stores a sufficient voleme ofcompressed air to provide five diesel engine starts without recharge. Each air receiveris kept charged by an electric motor-driven air compressor powered from theEmergency Electrical Power (EE) System. Each compressor has a small diesel enginebackup drive that can be manually connected in the event of loss of electric power.

The fuel oil (FO) subsystem consists of underground fuel storage tanks, fuel transferpumps, and engine delivery and injection components. The fuel oil is stored in twosafety-related underground fuel oil storage tanks (one per unit) which containsufficient capacity to provide continuous operation of one EDG in each unit at fullloadfor 7 days. The underground fuel oil storage tanks are filled from the abovegroundnon-safety-related FO System which provides fuel oil for all site needs. For each EDG,one ready fuel oil transfer pump takes suction from one of the two underground fueloil storage tanks, and one standby fuel oil transfer pump takes suction from the othertank. Either transfer pump fills and maintains the proper level of the day tank required

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for diesel generator operation. The day tank has sufficient capacity to support a fullyloaded engine for at least 3 hours.

The scavenging air and exhaust subsystem provides pressurized air to the dieselengine cylinders for combustion, and aids in exhausting the combustion gases.

The lubricating oil (LO) subsystem consists of an engine-driven pump, full-flow filter,cooler, strainer, immersion heater, motor-driven prelube pump, and a standbycirculating pump. This subsystem provides cleaned and cooled lube oil to the dieselengine and its components during operation.

The air-cooling subsystem consists of an engine-driven pump, a three-way mixingvalve, radiators, and aircoolers (aftercooler). This subsystem removes heat from thecombustion air in the scavenging air and exhaust subsystem. A three-way mixingvalve controls the flow through the radiators. During EDG operation, an engine-drivenair cooling pump circulates cooling water through the radiators for cooling and thento the aftercoolers in the scavenging air and exhaust subsystem. Cooling water isalso circulated through the radiator fan gear box cooler. The radiator fan assemblyprovides forced air flow over the radiators in both the jacket cooling and air coolingsubsystems by drawing ambient air into the Diesel Generator Room, over the radiatorfins, and exhausting through the roof.

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2.2 Emergency Electrical Power System

The Emergency Electrical Power (EE) System provides a highly reliable power source-

2! to Class 1E loads and certain non-Class 1E loads during all plant conditions . Figures

1 and 2 show one line diagrams of the emergency buses for Unit 1 and Unit 2i respectively. The EE System consists of two redundant power distribution systems.

One system is referred to as the train A (orange; H) system. The other system isreferred to as the train B (purple; J) system. Each EE System train consists of a4160V switchgear, two 480V load centers, and 480V MCCs, which supply power tomotors, motor-operated valves (MOVs), heaters, lighting, and other loads, which arerequired to be powered during normal and design basis event plant operatingconditions.'

Each train is normally energized continuously from the switchyard external gridsystem. This preferred power supply is available from the reserve station servicetransformers (RSSTs) via the transfer buses. Upon loss of the switchyard " preferred

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power supply," each EE System train is supplied by a " standby power supply," which'

consists of an on-site EDG. There are a total of four EDGs at North Anna, two perunit. Each 100-percent capacity EDG is connected to its assigned train and is

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available to pick up load within 10 seconds after receipt of a start signal. The Class,

IE loads are loaded onto the EDGs sequentially.

An additional supply source for the Unit 1H bus is the connection from the 1H bus tothe 1B bus. The 1B bus may be energized in the startup or shutdown mode fromRSST B (Figure 1). In addition, if the main generator breaker is open, the 1H bus maybe supplied through the main transformer, the unit station service transformer, andthe 1B bus tie, in a similar manner, the 1J bus may be supplied from the 2B bus.However, the only source of supply to the 2B bus, except for when Unit 2 isoperating, is from RSST B.

An additional off-site source of Unit 2 normal station service power can be madeavailable in 8 hours by removing the isolated bus duct disconnect links, backfeeding

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through the main transformers, and utilizing the normal station service transformers.The 2B bus then can serve as an alternative power source to power the emergencybus 1J for Unit 1. To minimize low-voltage effects on equipment during an EESystem emergency bus transfer from the off-site source to the diesel generators, the4.16kV Class 1E bus is divided into two sections: the normal Class 1E bus sectionand the stub bus section, which are connected via the stub bus tie breaker. The stubbus section supplies the component cooling and residual heat removal loads, whichare not immediately required during an accident condition. These loads on the stub

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2The information in this section is taken from the SDBDdocument " Emergency Power System, North Anna Power Station," SDBD-NAPS-EP, Rev. 1, Section 3.1, 12/31/93

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j bus are disconnected due to undervoltage on the bus, i.e., during transfer from the [; off-site to the on-site source, and may be reconnected either manually or) automatically, in addition, when a containment depressurization actuation (CDA) :

] signal occurs, the stub bus tie breaker is tripped and locked out. 1

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. For Unit 2, either 4160V emergency bus may be connected to the emergency bus of |j the opposite train, by an administratively controlled bus tie breaker. This connection i

j permits Class 1E equipment of one train to be powered by its opposite train {j emergency bus, which can get its power from either the RSST or EDG. Unit 1 does '

j not have this emergency bus tie breaker installed. r.

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2.3 Alternate A.C. Dieseli

: The AAC DG is a Caterpillar 3612, four cycle, turbocharged, after-cooled, diesel,

j engine. The AAC DG engine will operate at 900 RPM,4640 horsepower, to produce,

; 3300 electrical kilowatts on a continuous basis. In addition, the engine will bej capable of a "2000" hour rating of 3640 kilowatts. ;

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The fuel oil system consists of a day tank sized to allow diesel operation for up to four !3

hours without replenishment. The fill system for the diesel engine day tank utilizes-

: the auxiliary boiler fuel transfer pump with a supply line routed from the Auxiliary L

i Boiler Building to the Alternate A.C. (AAC) Building. Filling of the day tank is ani automatic process with pump and valve activation based on tank level. Additionally,j a gravity fed bypass of the pump is available.

| The AAC DG can be started by local operator action or by receiving an auto starti signal following the simultaneous loss of the D or E and F transfer buses. This logic| will prevent unnecessary diesel starts when a single emergency bus is lost (one RSST)

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i on a unit, while providing a diesel start when the potential exists for a station blackout|i

(i.e., loss of both emergency buses on a unit). After it has started, the diesel will be '

available for manualloading onto the desired transfer bus and subsequent emergency ii

! bus as shown in Figure 1 and Figure 2 for Unit 1 and Unit 2 respectively. |1

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|i Based on the train specific (loads powered from H buses only or J buses only) nature ;of some common systems, especially instrument air, it is desirable to power a H and;

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a J bus in order to deal with a station blackout. Therefore, if the H EDG is providing |j power to the non-blacked out unit, then the AAC DG will, if possible, power the J bus i

! on the blacked out unit. It is possible that an operator can power a J bus on both the!; blacked out and non-blacked out unit. Then the operator will have to take appropriate ;

! actions to restore power to an air compressor or to perform necessary actions without '

compressed air. ,

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""8 '"'near e must A nest e- ww aw - w rwtart ii 4KV BUS B 1sntie 6 sets inati4KV BUS B (UNIT 1) TRANSFER BUS F (LMT2) TRANSFER BUS D TPANSFER BUS E

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1sHtt i I IteH11 111sJ1 II 1M1STUB BUS 4KV BUS 1H 4KV BUS 1J STUB BUS,

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480V BUS 1H 480V BUS IJ

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Figure 1 - Power Supply to 1H and 1J Emergency Buses

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IIMIT A 05M3 ftBET B 0512 IEEET Cw au wT F9 ,e w-

F9isoi n ain 6am.i nina ninTRANSFER BUS D TRANSFER BUS E TRANSFER BUS F

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STUB BUS 4KV BUS 2H 4KV BUS 2J STUB BUS

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|480V BUS 2H 480V BUS 2J

Figure 2 - Power Supply to the 2H and 2J Emergency Buses

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Before Station Blackout (SBO) modifications were made the normal off-site feederbreakers from the transfer buses to the emergency buses (15D3,15E3,15F3 and15F4) were tripped and blocked from closing following a loss of off-site power, aRSST differential trip, a pilot wire trip or a trip of their associated main transfer busbreaker (15D1,15E1 or 15F1). These non-safety related breakers, however, must beclosed during a SBO with any or all of the mentioned conditions present. This hasbeen accomplished by adding a " NORMAL /AAC" switch on the AAC breaker controlpanel for each breaker (15D3,15E3,15F3,15F4). In the "AAC" position, this switchwill bypass / defeat the trip and close interlocks stated above. Once the transfer busbreaker is closed, the associated emergency bus breaker may be closed and thedesired emergency bus energized. The ability to close these breakers with 15D1,15E1, and 15F1 open has been proven during start up testing.

The existing electrical separation requirements which pertain to circuits related to theD and E versus the F transfer bus system and its feeders have been maintained. Thenew switchgear provides isolation of the AAC source from the normally energizedtransfer buses. This arrangement also minimizes the increase in exposure of theenergized transfer buses during normal operation by maintaining them in theirassociated Switchgear Room.

Diesal control panels are provided in the AAC Building. Three panels are provided bythe diesel manufacturer and contain the controls required for manual diesel operation,and the operation of its support equipment as well as recording parameter variationwith time. General annunciation is provided remotely in the Control Room to indicatediesel trouble / diesel tripped / diesel running /RSST A paralleled with RSST B/ bus OL andbreaker 15F5 alarms. Specific problem annunciation is provided locally to enhancetroubleshooting efforts.

A bus relaying panelis located adjacent to the diesel generator monitoring panel. Thispanelis supplied by the switchgear manufacturer. The panel contains the generator

| protection relaying. There is also a control panel installed adjacent to the dieselgenerator control panels which provides remote control of the new AAC systembreakers. These breakers were added to provide the electrical connection betweenthe transfer bus and the AAC DG.

2.4 Description of EDG Preventive Maintenance inspection

Once every 18 months each of the EDG undergoes preventive maintenance andinspection appropriate for diesels used for this class of standby service. This |maintenance involves disassembly of the major subsystems in order to clean andinspect components. A list of the components which are included follows:

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inspection Covers and Exhaust ManifoldCrankshaft Coupler Pointer CheckCrank Leak CheckFuel injection Timing Checkinspection of Fuel Oil Pump Shaft Sealinspection of Governor and Fuel Pump Driveinspection of Lube Oil Pump and Coolant Pump Drive Gearsinspection of Upper Torsional DampersInspection of Lower Torsional Dampersinspection of Lube OilInternal Pipinginspection of Pistons, Rings, and Cylinder LinersInspection of Blower Flexible Drive, Timing Gears and Spring Packs

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inspection of Timing Chain, Sprocket and Sprocket BearingMeasuring Lower Crankshaft Strain on Cylinders No.11 and 12Upper and Lower Main and Connecting Rod Bearing inspection-

inspection of Vertical Drive Shaft Gears and Coupling,

Checking Crankshaft Thrust Bearing ClearanceChecking Torque of Crankshaft Coupling BoltsFuelinjection Nozzle Opening Pressure Check and Seal Leakage CheckAir-Start Check Valve and Distributor inspection,

Inspection of Cooling Water Side of Lube Oil CoolerEngine Block Coolant Hydrostatic TestCleaning and inspection of Crankcase Assembly and Cleaning Oilseparator / BreatherLube Oil System Maintenance

i Fuel Oil Day Tank Foot Valve Strainer MaintenanceChanging Oil in Woodward EG-B10 Governor;

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Blower Lobe and Housing ClearancesBlower inlet Air Filter inspectionInstalling Exhaust Manifold and Engine inspection CoversCleaning Standby Lube Oil HeaterRefilling Engine Sump (if Drained)

Historically, this maintenance has been performed during refueling outages (i.e.,Modes 5 and 6) when Technical Specifications require only one EDG to be operable.A review of the maintenance records, by station personnel, shows that the above listof activities requires about fourteen days to complete in the worst case. On averageit takes about ten days to perform this work (i.e., with no unplanned additionalactivities).

Two crews work to support the EDG maintenance. Obviously, this represents a costthat will be incurred regardless of when the dieselis maintained. However,if the EDGinspection can be performed when the unit is on-line, the crews doing this

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maintenance can work on other outage activities during refueling operations. So,more of the outage work can be performed by Virginia Power personnel. This actionrepresents a cost savings because there are fewer contractor personnel required. inaddition it is estimated that one day of critical outage time can be realized using this

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3.0 PSA ANALYSIS

The PSA analysis was performed with a model of North Anna that represents thecurrent operation of the station. The IPEEE model was upgraded and enhanced,including use of the newest version of NUPRA . Each stage of the development is8

summarizad below.

Upgrade, enhance and solve the IPEEE model using the latest version of>

NUPRA.(EDG-TM)Update the plant specific EDG unavailability data used in the IPE to>

account for operating practices during the last five years. (NO-AAC)Add the AAC DG to the current model with the updated data. (95 JUNE)*

Increase the maintenance unavailability of the EDG to represent the><

' single 14-day outage per 18 months for each EDG. (EDG-AOT)Run a sensitivity case with EDG unavailability extended beyond the 14->

day window. (BOUNDING)

3.1 Comparison to IPE model

The North Anna IPE model was submitted to NRC in December 1992'. A request foradditional information (RAl) was received and the response was submitted on April

528,1995. The IPEEE model, submitted in June 1994', is similar to the IPE model butJ

3"NUPRA 2.2 Users Manual," NUS Corporation, March 1994.

d" North Anna Power Station Units 1 and 2 Response to GenericLetter 88-20 and Supplement 1, Individual Plant Examination (IPE)for Severe Accident vulnerabilities," Letter from W.L. Stewart toUSNRC, Serial No. 92-774, December 1992 with Final Report asEnclosure.

5" North Anna Power Station Units 1 and 2 Individual PlantExamination (IPE), Request for Additional Information," Letter fromM.L. Bowling to USNRC, Serial No. 94-740A with enclosure.

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incorporates plant changes and model enhancements since the IPE model wascompleted. Two minor hardware modifications thought to have significance toprevention of core damage were added to the model. They were a tie-in to thebearing cooling system to create an alternate supply of cooling water to theemergency switchgear room chillers and the capability to use fire water as a backupsupply to the charging pump lube oil heat exchangers. The PSA model was solvedwith these modifications included and the result was a slightly lower overall CDF.

Some model enhancements and event tree structure changes were also made to theIPE model. The model enhancements were made to take advantage of increasedcomputing capability and reduce manualiterations. The primary event tree changesinclude developed fault trees for equipment from the unaffected unit. The treesaffected by this change are loss of seal cooling (T4), loss of service water (T6), andloss of emergency room switchgear cooling, (T8). Table 3.1 summarizes the eventtrees used in each model.

There are significantly more event trees listed for the IPEEE than the IPE. The numberof accident initiators remains the same in both models. The original event trees werespiit into smaller trees with less sequences to improve the utility of the two trees. Forexample, by splitting the large LOCA tree into two the number of sequences on eachpage is cut in half and therefore is much easier to read. The accident sequencestructure did not change for most accident initiators. However, as mentioned abovethe structure of the T4, T6 and T8 trees were changed. Each of these trees isdiscussed below.

The T4 tree modification involves an alternate interpretation of the seal LOCA model.In the IPE, successful depressurization was assumed to avoid a seal LOCA. Followingthe IPE solution, it was evident that this depressurization assumption did notsignificantly affect overall CDF, and a more conservative approach could be adopted.Therefore, for the IPEEE, the depressurization function was assigned a value of 1.0.The impact of this change is that core damage can only be avoided if the loss of sealcooling is mitigated using the core cooling recovery strategy given in the emergencyresponse guidelines. The T4 contribution to core damage frequency doubles, relative |

to the IPE, to ~ 2E-8/yr. Hence the change is not significant but represents consistentseal LOCA modeling among the event trees. !

The loss of service water tree (T6) was changed more substantially. Given the loss iof service water there is a loss of RC pump seal cooling and ESGR cooling. Either of I

these lead to core damage by causing a seal LOCA unless a different heat sink can befound. Fortunately, another heat sink is available for each component. The use of

'" Individual Plant Examination Of Non-Seismic External Eventsand Fires, North Anna Power Station, Units 1 and 2," Final ReportVolumes 1 and 2, April 1994.

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{ these alternate heat sinks was developed to support the large service water piperestoration project at North Anna and are now part of the plant design. As a result,; )

the revised loss of service water event tree does not consider the state of the sealsbut instead considers the probability of recovering the lost heat sink. The T6 1

contribution to core damage increases to ~ 5E-7/yr as compared to 4E-9/yr reported ,

for the IPE. While the difference is about two orders of magnitude it should be notedthat the absolute value is still quite small at about 0.9% of total core damage :

frequency. ;

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The final tree with structural changes is the loss of emergency switchgear roomcooling event tree (T8). Once the event occurs it is not an issue of depressurizationas much as it is one of needing to provide alternate RC pump seal cooling before it islost. Since the T8 initiating event affects only one unit, the equipment on theunaffected unit is available to mitigate the loss of seal cooling. Therefore, the treehas been structured to use HVAC from the unaffected unit to cool the affected unit.There are two ways to accomplish this goal: use fans to blow cool air into the

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affected ESGR or cross connect the seal cooling equipment from the unaffected unit. '

If the first action fails but the unaffected unit HVAC still functions, it is possible to I

use charging and component cooling from the unaffected unit to supply see! injectionand seal cooling to the affected unit. As a result of these changes the lots of ESGRcooling initiating event contributes ~ 6E-7/yr to CDF as opposed to ~ 7E-6/yr usingthe IPE model.

The core damage frequency was nearly the same for both solutions. The IPE coredamage frequency is 6.8E-5/yr while the IPEEE core damage frequency was 6.3E-5/yr.The differences in the results between the two solutions were reviewed and found tobe non significant based on a comparison of the cut sets for each function. Some ofthe IPEEE event trees were used in the analysis of fires as reported in the Non-Seismic

7IPEEE final report .

The PSA software used by Virginia Power has evolved as PC hardware capabilities '

have improved. One significant advancement is that NUPRA now allows batch modesolution of the entire PSA model. Therefore, the first step in the analysis of extended !

allowed outage time was to convert the model to the most recent version of NUPRA.This conversion must show that the results with the new code version are the sameas the previous results or that any differences are understood. The EDG-TM run |served this purpose,

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The differences between the IPEEE and the EDG-TM are attributable to several factors iincluding: the function truncation limits were set at 1E-9 versus 1 E-10; undeveloped

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7" Individual Plant Examination Of Non-Seismic External Eventsand Fires, North Anna Power Station, Units 1 and 2," Final ReportVolumes 1 and 2, April 1994.

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transfers from the earlier models were deleted; and two new functions were addedto the T1 event tree, providing status of the Unit 1 and Unit 2 EDGs, to facilitatedevelopment of the AAC model. The core damage frequency for the IPEEE modelis6.3E-5/yr while the EDG-TM model yields a core damage frequency of 5.7E-5/yr. ;

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3.2 Revised EDG Unavailability Data I

in addition to conversion to the latest version of NUPRA, the EDG test andmaintenance unavailability is updated with recent plant specific data. Improvements !in EDG preventive and corrective maintenance practices have lowered the EDG 4

unavailability. A more accurate EDG unavailability is desirable not only to lower SBO |and total CDF results, but also to provide faithful risk ranking for applications such as !

the 10 CFR 50.65 maintenance rule. The North Anna IPE data analysis methods were '

used to revise the EDG unavailability estimate. Plant records for the 1990 through,

4

~ 1994 interval indicate an average EDG unavailability of 97.30 hours per EDG peri

calendar year. This EDG unavailability rpplies to plant operation in Modes 1 to 4, and i

is felt to conservatively estimate at-power EDG unavailability (Modes 1 and 2 only). |Critical-hours from NUREG-0020 were used to estimate EDG exposure for at-power i

operation. For the 1990 to 1994 interval, the average unit (or EDG) critical-hour '

exposure is 7601.66 cr-hrs per calendar year. Combining the 1990-1994 EDGunavailability with the EDG exposure yields en unavailability probability of 1.28E-2. ;This can be expressed in terms of hours as 112.2 hours / critical-year or in terms of ;

days as 4.7 days / critical-year or 4.1 days per calendar year.

The PSA model includes components from Unit 2 systems that can be cross- !

connected to Unit 1 requiring consideration of opposite unit diesel unavailability. jFurthermore, the opposite unit EDG unavailability must include all modes of operation !

since the unaffected unit may be down when the affected unit is at power. This isaccomplished by determining how many hours of diesel unavailability there are when ;i

the unit is in Modes 3 to 6 and adding that to the diesel unavailability during Modes1 and 2. '

Based on a review of available data and discussions with plant personnel it was Iconcluded that the total unavailability per diesel is conservatively estimated to have |been 23 days per fuel cycle during 1990 to 1994. Converting 23 days of diesel i

-

unavailability every 18 months to a 12 month basis results in 23 * (12/18) = 15.33

days per calendar year. Adding this to the 4.7 days per critical year of unavailabilityduring Modes 1 and 2 results in a total of 20 days per critical year or an unavailability |of 5.48E-2. This is equivalent to 17.3 outage days per calendar year. !

t

| The use of this data bounds the expected conditions for the revised operating ;strategy. If the EDG maintenance is performed on-line there will be 14 days of j

'

| opposite unit EDG preventive maintenance and inspection outage plus normal EDG ;,

p

!

15/

!

!- , - - - - .- -

. _ - . .-_.-.- - - - - . - ~ - _ -- _ - - - - - - . . . - - _ . -- ..

,

_

__

!|

|

}' |

unavailability. However, the EDG unavailability during opposite unit shutdown will ;

decrease to 3 or 4 days. Thus, the total days of EDG unavailability should be aboutthe same for either operating strategy.

!;The impact of the changes in EDG unavailability models can be seen through the ,

reduction in CDF from the EDG-TM model (5.7E-5) to the NO-AAC model (5.4E-5).(A summary of all of the results is shown in Table 3.2). Hence the increased,

j avaliability of the diesels reduces core damage frequency ~3E-6/yr.

i'

;'

i 3.3 AAC DG TM L

! |

The AAC DG manufacturer recommends a major tear down maintenance inspection,,

similar to the 18 month preventive maintenance and inspection of the EDG, but only,

; once every ten years. The AAC DG is not required to be operable by Technicali Specifications but is required to have a high availability to meet the SBO Rule; Guidelines. There is no readily available operating history to use as a basis for the !j AAC DG test and maintenance unavailability. It is reasonable to estimate the AAC DG| unavailability with that used for the Unit 2 EDG TM unavailability when Unit 1 is i

j operating. This is conservative to the North Anna IPE generic industry data for EDGj unavailability by a factor of two.

:

Ij 3.4 AAC DG Base Case

The AAC DG, recently installed to meet the requirements of the station blackout rule,,

j is now fully operational. This diesel represents an independent source of emergency) power that can feed any one of the four 4160V emergency buses at North Anna.| Therefore, it is postulated that this AAC DG can serve as a replacement to the EDGj during the preventive maintenance and inspection outage if it is performed on-line. i;

) The 95 JUNE model provides the positive impact of the AAC DG when it is available.In other words this model provides the estimated core damage frequency given that

j the AAC DG is available and the EDGs continue to experience the same number ofi hours of maintenance unavailability.;i

r

; it should be noted that this diesel can not serve as a replacement for an EDG for alli initiating events because the AAC DG is loaded manually. The need to load the diesel'

manually is a design feature which is intended to reduce common mode failures asi required by the station blackout rule. It is assumed that it takes one hour to start and

load the AAC DG. One hour is conservatively chosen since it is the longest time.! permitted by the station blackout rule.4

16

:.

. _ .

._.

A human factors viewpoint is used to evaluate the PSA initiating events to determinewhich events occur so rapidly that there is insufficient time to load the AAC DG.Severalinitiating events proceed to core damage in less than one hour without poweravailable including: Large LOCA (A); Medium LOCA (S1); Reactor Vessel Rupture(Rx); interfacing system LOCA; and ATWS (Th). The assumption that AAC DGcannot mitigate core damage for these initiating events is executed by special PSAmodel logic.

The AAC DG is potentially available for any emergency bus for the remaining initiatingevents. The PSA modells structured so that only one emergency bus can be poweredfrom the AAC DG. Furthermore, if either of the Unit 2 diesels is failed the AAC DGis assumed to only provide power to Unit 2. This approach conservatively modelselectric power recovery at Unit 1.

The above restrictions are incorporated by revising certain aspects of the station andunit blackout models. Each of these are discussed below in some detail. Thesignificant changes to the EDG-TM modelinclude common cause modeling and theaddition of the AAC DG system model.

The addition of the fifth diesel to the PSA model complicates the EDG common causemodel. First, the criterion for the purchase and installation of the AAC DG was tominimize common cause failures between this fifth diesel and the other EDGs.Second, the PSA model considers only one unit, so the station impact of a five or fourdiesel common cause failure is not straightforward. Third, the IPE utilizes the multiplegreek letter method for EDG common cause failures, and this 11 fault model couldbecome unwieldy with an additional diesel. The 95 JUNE PSA solution chose tosimplify the EDG common cause model in a conservative manner, reducing the 11fault model to a 3 fault model. Two faults are unchanged, the Unit 1 two EDG faultfor 1H and 1J diesels, and the Unit 2 two EDG fault for the 2H and 2J diesels. The

t remaining two EDG common cause faults and all the three EDG common cause faultsare combined with the four EDG common cause fault. This approach is conservativeand ailocates the common cause failures among the two units.The system model for the AAC DG is similar to EDG model. It considers the typicalelectrical equipment failures that prevent the transfer of electrical energy to each ofthe three transfer buses. These failures include breaker failures, maintenanceunavailability, AAC DG fail-to-start and fail-to-run. The fault tree resulting from thesystem modelis shown in Appendix A.

The addition of the AAC DG reduces core damage by requiring three failures, insteadof two, to fail both 4160 V electrical buses after a loss of off-site power. The95 JUNE model represents the current plant hardware configuration, and with theaddition of the AAC DG, the core damage frequency is reduced by ~1.3E-5/yr to4.1E-5/yr compared to the NO-AAC model shown in Table 3.2.

1' 17

|

________ ______________________ - ___ _ _ - _ _ . _ _

_ _ _ _ _ _ _ _ _ _ __ _ _ _ _ _ _ - -

.

3.5 Extended EDG Unavailability

For the EDG-AOT model, the EDG unavailability is increased to reflect the assumptionof a single, fourteen day maintenance outage once every eighteen months for eachEDG. Actually, the 95 JUNE model data is applied to the EDG-AOT model, except forthe Unit 1 EDG maintenance unavailability basic events. The 14 day preventivemaintenance and inspection outage time is added to the existing unavailability todetermine the impact of the proposed EDG Technical Specifications changes. A 14day outage performed once every 18 months is equivalent to 9.3 outage days, or 224hours, per calendar year. Adding this unavailability to the 97.30 hour plant dataunavailability of yields a total unavailability of about 321.3 hours. Combining this321.3 hour unavailability with the 7601.66 cr-hrs per calendar year exposureproduces a new unavailability probability of 4.23E-2.

The EDG-AOT model solution yields a core damage frequency of 4.2E-5/yr. The95 JUNE model CDF of 4.1E-5/yr is the base case against which the difference of 1E-6/yr from the EDG-AOT case represents an acceptably small increase.

3.6 BOUNDING Model

A final model was created to study the effects of EDG unavailability on CDF. Thismodel is . named " BOUNDING", and represents a sensitivity study on EDG :

unavailability. The maintenance unavailability was set equal to 40 days per calendaryear for all five diesels. The resulting CDF is 4.7E-5/yr.

3.7 Results

Each of the five cases produced reasonable results. A summary of the cases is shownin Table 3.2. The CDF contribution from the each initiating event is shown in Table3.3. Table 3.3 is a listing of core damage frequency sorted by accident group andaccident type. The fault trees which have been changed since the IPEEE model wascreated are included in Appendix A. The event trees for the 95 JUNE model areincluded in Attachment B. The results show that the electrical transient accidentinitiators are sensitive to the inclusion of the AAC DG and to varying the EDGunavailability. Other accident initiators are less sensitive to the AAC DG and EDGunavailability.

The LOCA transients shown in Table 3.3 contribute the same to core damagefrequency with and without the AAC DG in operation as shown by the subtotal for the"NO-AAC", "95 JUNE" and "EDG-AOT" cases. Also, the EDG unavailability does notimpact the contribution of this initiating event group. The same conclusion can bedrawn for the general transient group of initiating events. The electrical transients are

;

18

|

._- ._ -

. -- -. - .- . - .- _ . - - - . . - - - . - .

J impacted by both the AAC DG and the increased EDG unavailability. The inclusion ofj the AAC DG results in a significant reduction in CDF of ~ 1.3E-5/yr (i.e.,"NO-AAC"-

"95 JUNE"). This reduction is entirely from the electrical transients subgroup. ),

4

Thus, the initiating event groups with the largest contribution are the those involvingloss of electrical power and include the T1 and T1EE trees. These trees have incommon the loss of off-site power as an initiating event. This fact makes the diesel !

4

generator arrangement important. In the other trees, a coincident loss of off-site|

J power must occur before any diesel dependencies are realized. Unless the initiatingevent involves a loss of off-site power there is only a small impact from the extended,

; EDG unavailability on the contribution of that initiating event group to core damage'

frequency.

'

The T1EE event tree represents the loss of off-site power and failure of the EDGs onj Unit 1; or in other words a unit blackout. This event tree is the largest contributor to| core damage until the AAC DG is added to the model. The AAC DG decreases thei contribution of this initiating event group from about 22% to about 14%. When the

extended diesel generator unavailability is added the contribution increases only.

slightly to about 16%. The change in core damage frequency is ~ 1E-6/yr due to thisi extended EDG unavailability. This represents an average annual increase but, it; actually occurs over two separate fourteen day intervals; one for the 1H diesel and; one for the 1J diesel. Thus, it is concluded that the AAC DG is an adequate source

of replacement power for an EDG for the limited outage required to perform the 18-i

month inspection.

i The PSA models assume that other risk significant equipment is unavailable on anaverage annual basis. However, it is important that on-line maintenance be performed,

j in an integrated fashion so that all risk significant components are considered. Thisimportant consideration is ensured by the administrative controls in place for,

i performing on-line maintenance. These controls are based on a list of risk significantequipment which was developed from the North Anna PSA model. The controls,

involve scheduling of on-line maintenance. Scheduling of equipment for on-line; maintenance is to be performed in a way that minimizes simultaneous outages of riskj significant equipment. Special emphasis is given to limiting on-line maintenance whenj the electrical distribution system is at less than full capacity.J

,

e

$

d

19

1

_ _ _. . . - - . . - .-

|

4

Table 3.1 - Comparison of Event Trees Between The IPE and the IPEEE

. Event Tree IPE .IPEEE

Large LOCA A A,AD2

Vessel Rupture Rx Rx)'

1Medium LOCA S1 S1,SID1

Small LOCA S2 S2,S2D1

Loss of Off-site Power T1,T1Tr,TIA T1,T1Q,T1QFW,T1Hv,TIEG,TIEGQ

Transient - Loss of MFW T2,T2Tr T2,T2HV

Transient - MFW Recoverable T2A,T2ATr T2A,T2AHv

Transient - MFW Available T3,T3Tr T3,T3HV

Loss of RCP Seal Cooling T4 T4 |

|Loss of Emergency Power DC Bus 1-I T5A T5A,TSAQ

Loss of Emergency Power DC Bus 1-III TSB TSB,TSBQ '

Loss of Service Water T6 T6

Steam Generator Tube Rupture T7 T7,T7D1

Loss of ESGR Cooling T8 T8

Loss of Emergency Power - Bus 1H T9A,T9ATr T9A,T9AQ,T9AHv

Loss of Emergency Power - Bus 1J T9B,T9BTr T9B,T9AQ,T9BHv

ATWS TH,TL TH,THMFW,TL |Interfacing System LOCA VX VX 1

!

|s'

i

|

|

,

!

|

4 |

) 1

.

1

20 -

1i

-

5 5 5 5 5 5 5Fr - - - - - - -

by E E E E E E ECl 8 3 7 4 1 2 7

6 6 5 5 4 4 4

_ GD A A A 3 3 3 0

/ / / 7 7 7 0.C N N N 1 1 1 4Ara AeYredne

- l

a ;

C 2's r tG 7 7 7 3 3 3 0k e iD 1 1 1 7 7 7 0 -nu Ps U E 3 3 3 1 1 1 4 -

-

e s -yR -aDf

O-

-

e -

y gr aa t

m u1

m O i 2u G 5 5 5 1 1 4 0tS iDn 3 0- E 5 5 5 4 4 1 4U' 2 '

3e

l

baT

G ~oDN/ o o o o s s s

e e eCs N N N N Y Y YAeA Y

.

eT Gm M C E

N E E T A N O Na E I

A U A D-P E G N-l

P J G U-e I

d D O 5o E N 9 DI

OEM B

,

|| ||f

_ _ . _ ._ . ._ . . - - .

. Table 3.3 ' '

-

Cofe Damage Frequency For'Esch Accident Group For Each North Anne PSA Model - - '

,

Accident IAccident ' . 94 Jan D - 92 DecGroup Type: ' BOUNDING EDG AOT 95 JUNE ~ NO AAC . EDG-TM - :.(IPEEE) (IPE)

LOCA S2 9.87E-6 9.86E-6 9.86E-6 9.89E-6 9.90E-6 9.84E-6 1.01 E-5*

T7 7.58E-6 7.57E-6 7.57E-6 7.59E-6 7.60E-6 7.34E-6 7.02E-6s

S1 6.76E-6 6.75E-6 6.75E-6 6.75E-6 6.75E-6 6.73E-6 6.64E-6

A 4.06E-6 4.06E-6 4.06E-6 4.06E-6 4.06E-6 4.48E-6 4.09E-6Vx 1.60E-6 1.60E-6 1.60E-6 1.60E-6 1.60E-6 1.60E-6 1.60E-6

'

Rx 2.67E-7 2.67E-7 2.67E-7 2.67E-7 2.67E-7 2.67E-7 2.68E-7T4 2.43E-8 2.43E-8 2.43E-8 2.43E-8 2.43E-8 2.43E-8 1.07E-8

Subtotal 3.02E-5 3.01 E-5 3.01 E-5 3.02E-5 3.02E-5 3.03E-5 2.97E-5

|

|

[.

k

22

-. _ - _ . . ._ . _ . - . - - .. . - - - . - . . -. . -.. . . _ - - . . . .. - -. . -. . - - _ . .

. - . _ ._ . - _ ... . ..

Table 3.3~ Core Damage Frequency For Each Accident Group For Each North Anna PSA Model

Accident : Accident ' 94 Jan - 92 DecGroup - Type . BOUNDING EDG AOT' 95 JUNE NO-AAC : ' EDG-TM ~ (IPEEE) . (IPE)

Electrical TIEE 8.83E-6 6.53E-6 5.85E-6 1.17E-5 1.32E-5 1.80E-5 7.98E-6"

T1 4.14E-6 2.19E-6 1.67E-6 7.82E-6 8.76E-6 9.89E-6 4.60E-6

T9AHv 2.66E-7 2.13 E-7 2.01 E-7 3.87E-7 4.37E-7 2.26E-7 3.26E-6

T98 2.17E-7 1.62E-7 1.47E-7 3.25E-7 3.54 E-7 3.38E-7 5.81 E-7

T9A 1.59E-7 1.17E-7 1.06E-7 2.40E-7 3.42E-7 2.50E-7 4.15E-7

T1Hv 2.58E-7 1.04 E-7 7.70E-8 7.53E-7 1.15E-6 1.50E-6 7.27E-6

T9BHv 7.01 E-8 7.01 E-8 7.01 E-8 7.03E-8 7.10E-8 7.48E-9 6.78E-8

TSA 2.35E-8 2.04 E-8 1.96E-8 2.95E-8 3.10E-8 2.95 E-8 1.11 E-7

TSB 1.77E-8 1.77E-8 1.77E-8 1.81 E-8 1.84E-8 3.52E-8 1.09E-7

Sub-total 1.40E-5 9.42E-6 8.16E-6 2.13E-5 2.44E-5 3.03E-5 2.44E-5

23

_- .- _ _ _ _ - _ _ - - - _ - _ _

_ _ - _ _ _ _ _ _ _ . _ _ _ _ _ _ _ _ _ _ _ _ .

I

Table 3.3 -Core Damage Frequency For Each Accident Group For Each North Anna PSA Model

- Accident Accident 94 Jan 92 Dec- Group ' LType BOUNDING - EDG-AOT 95 JUNE ~ NO-AAC EDG TM - (IPEEE) (IPE)

General T8 6.53E-7 6.17E-7 6.17E-7 7.04E-7 7.90E-7 5.67E-7 6.56E-6*" "

T6 5.39E-7 5.39E-7 5.39E-7 5.39E-7 5.39E-7 5.39E-7 4.52E-9

TH 4.24 E-7 4.24E-7 4.24E-7 4.24 E-7 4.24E-7 4.25E-7 4.20E-7T3Hy 3.92E-7 3.92E-7 3.92E-7 3.97E-7 4.06E-7 1.19E-7 4.06E-6

T2 3.45E-7 3.45E-7 3.45E-7 3.45E-7 3.45E-7 3.28E-7 8.86E-7

T2AHv 1.57E-7 1.57E-7 1.57E-7 1.59 E-7 1.61 E-7 3.94E-8 1.65E-6

T3 1.68E-8 1.59E-8 1.59E-8 1.96E-8 2.05E-8 2.09E-8 7.61 E-8

T2A 1.45E-8 1.42E-8 1.42E-8 1.54E-8 1.57E-8 1.51 E-8 6.11 E-8

T2Hv 1.39E-8 1.39E-8 1.39E-8 1.39E-8 1.39E-8 2.80E-9 1.44 E-7

TL 4.23E-10 4.23E-10 4.23E-10 4.23E-10 4.23E-10 4.23E-10 0.0

Sub-total 2.54 E-6 2.52E-6 2.52E-6 2.62E-6 2.72E-6 2.06E-6 1.39 E-5

Grand Total 4.67E-5 4.21 E-5 4.08E-5 5.42E-5 5.72E-5 6.27E-5 6.79E-5

|

24

_ _ _ - . _ _ ._ ._ -__ .. . _ _ _ _ _ _ -

_ _ _ _ - _ _ . .. ._- _____ ~ __ .___. _ _._-._ _ -_ ___

4.0 ACCEPTABLE RISK INCREASES

Virginia Power has determined what constitutes an acceptable risk increase for theproposed Technical Specifications changes. This determination was based on areview of existing documents and the selection of the guidelines most applicable toNorth Anna Power Station. The pertinent documents are summarized below.

,

The EPRI PSA applications guide discusses the concept of a permanent modificationwhich is essentially what is proposed herein. The modification is to the TechnicalSpecifications not the plant hardware. The EPRI document states that a permanentrisk increase can be determined as a percentage of the base CDF. The calculation forNorth Anna follows assuming that the base case is the IPE model submitted previouslyfor NRC review.

log ( A,) =-0. 5 * log (CDFw%) -1

For North Anna the baseline core damage frequency (CDF%)is 6.8E-5/yr. So, theacceptable risk increase (Acor) is given as

'log (Ay) =-0. 5 * log (6. 8E-5) -1

Evaluating by reducing the right-hand-side and making both sides an exponent of base10 gives -

A ,=12.1

h!

Hence based on the above formula, a 12.1 % increase in core damage frequency couldbe justified for a permanent increase. This increase is comparable to the contribution ,

| from the largest initiating event categories. It is larger than the largest contribution| from any sequence.

The Brookhaven NUREG/CR study of risk based technical specification development.

does not discuss risk increases in general but does treat the subject of Allowed |Outage Time increases. The document discusses when a sensitivity analysis can be '

used in lieu of re-solving the model. One of the criteria it gives for the acceptabilityof sensitivity analysis is if the overall equation has minimal cut sets for the downcomponent that have "a non-negligible contribution, i.e., have a contribution greater

;than 1 %."' A complementary statement to this is that those cut sets which '

| contribute less than 1.0% have a negligible contribution. Therefore, another possible|

.

'" Handbook of Methods for Risk-Based Methods for Analyses ofTechnical Specifications," NUREG/CR-6141, page 3-8, December 1994.

,

25

--

|

acceptable risk increase criterion is 1.0% of the base core damage frequency whichfor North Anna would be 6.8E-7/yr using the IPE as the base model.

The use of 1.0% of core damage frequency as the cutoff value is similar to the typesof cutoffs that have been chosen in other applications. For example, the reportingguidelines for the individual plant examination require core damage sequences greaterthan 1E-7 per year and within the upper 95 percent of the total core damagefrequency to be reported. The NUMARC guidelines for the maintenance rule definerisk significant components in several possible ways'. One way is the use of the coredamage frequency contribution. Cut sets that account for about 90% of the overallcore damage frequency, with appropriate eliminations, should be used as input to riskdetermination. Since a cut set can appear in only one sequence this is the same asa sequence requirement and is obviously less restrictive than the 1% numberdiscussed above.

Finally, consider that the screening cutoff for the IPEEE, including FIVE, is 1E-6/yr' .This is comparable with the 6.8E-7/yr representing 1 % of the core damage frequencyas indicated by the North Anna IPE.

As a result of the above discussion it is clear that the use of something on the orderof 1% as an acceptable risk increase is within the bounds used by NRC and itscontractors for PSA applications. It is also clear that it is more conservative thansome of the measures discussed. Based on this review of industry experience,1E-6/yr has been adopted by Virginia Power as the figure of merit for use in theevaluation of the extended EDG outage.

5.0 IMPLEMENTATION REQUIREMENTS

An implementation plan is necessary to ensure that analysis assumptions are properlyincorporated into station operating procedures. The plan presented below has twocomponents: equipment required to be operable during the extended EDGmaintenance outage and other safety related equipment potentially available for on-linemaintenance.

The off-site power sources and other (i.e., both units) EDGs must be operable duringthe EDG extended outage when the inspection and maintenance is performed during

'" Industry Guidelines for Monitoring the Effectiveness ofMaintenance at Nuclear Power Plants," March 1993.

''" Procedural and Submittal Guidance for the Individual PlantExamination of External Events (IPEEE) for Severe AccidentVulnerabilities - Final Report," NUREG-1407, page 4, June 1991.

26

'- . _ _ _ _ - - - - - - _ _ _ - - - - - - - - - - - - - - - . -

. _.

.. . .. . . ..

operation in Modes 1,2,3 or 4. Additionally, the AAC DG must be operable as definedin the Technical Requirements Manual. Operability includes the EDG set and severalsubsystems, such as the fuel transfer system, in a manner similar to the EDGs. '

Surveillance requirements have been defined for these AAC DG subsystems and somespecific components. The AAC DG operability items are listed in Table 5.1. Inaddition to these operability requirements in Table 5 the AAC DG must be testedwithin 14 prior to removal of an EDG for its preventive maintenance inspectionoutage. During this testing the AAC DG must be aligned to the transfer busassociated with the emergency bus powered by the EDG to be inspected, j

A procedure must be written to address the use of the AAC DG for each of the EDGs.The procedure must address the controls for starting the diesel and individual breakerposition for providing power to each bus. The procedure should include an equipmentload list with priorities for the order in which equipment are loaded onto the bus.

1

1 Performance of additional on-line maintenance concurrent with EDG preventivemaintenance during the fourteen day extended outage is governed by existing on-linemaintenance administrative controls which rely on a list of risk significant equipmentdeveloped from the North Anna PSA model. The administrative controls currentlyrequire that only one functional equipment group, FEG, (i.e., all of the subcomponentswhich must function in order for a major piece of equipment to function) beunavailable for planned maintenance at the same time.

If two or more risk important FEGs for a unit are to be unavailable additionaladministrative controls may be required. However, during the extended EDG outageif two or more FEGs are to be unavailable at the same time, for any reason, acontingency plan outlining compensatory actions should be developed.

The performance of this inspection outage during modes 3 and 4 has not beenspecifically analyzed. The at-power PSA model is not appropriate for theseconditions. NUREG/CR-5994" considered the effect of EDG maintenance on coredamage frequency during various modes of operation. The study concludes that EDGmaintenance in shutdown modes prior to an outage should be avoided because decay )heat generation is highest and steam to power the turbine driven auxiliary feedwater

{pumps may not be available.i|

The administrative controls currently in place preclude on-line maintenance to FEGson systems important to PSA safety and components important to plant reliabilityduring planned transients. So, this type of maintenance would not be started duringa planned evolution into Modes 3 or 4. However, if a unit is forced to enter into these

"" Emergency Diesel Generator: Maintenance and FailureUnavailability, and Their Risk Impacts," NUREG/CR-5994, Chapter 5,November 1994.

27

._ ._ _ _ - _ _ _ _ _ _ _ _ _ _ _____ -_- __ _ _-___ -_____-__ _ -

. _ _ _ _ _ . _ _ . . _ _ _ _ _ . _ __

;

i

!

it

modes while the EDG maintenance is in progress, the increase in core damage4

i frequency resulting solely from changing modes does not require continued cooldownas long as sufficient secondary heat removal capability exists. Sufficient secondaryheat removal capability exists if there are at least two sources of feedwater available.The main feedwater system, the auxiliary feedwater system or a combination of the.

; two could be used for this purpose. The operability assumptions related to the EDGi outage (items 1,2 and 4 above) must also continue to be met. If at least two sources

of feedwater cannot supply their respective steam generators the unit should be,

j brought to cold shutdown.i I3

!. . . .

. ' yTable|5.1} . .. ..

i; . . .Altern' ate A.CiDiesel Operability Requirementsi.-

,

;

1. Verify that the volume of fuel oil in the day tank is greater than or,' equal to 850 gallons.

j 2. Verify that the volume of fuel oil in the above ground fuel oilj storage tank is greater than or equal to 45,000. ;.

3. Verify that a fuel oil transfer pump can be started and transfers ;.

i fuel from the storage system to the day tank, or verify gravity || feed flow to the day tank is > 4 gpm, or verify gravity feed flow || is sufficient to maintain the day tank level while the AAC DG is !

i loaded > 3250 kw. !,

: 4. Verify that the AAC DG can start and accelerate to synchronous |t speed (900 rpm) with generator voltage and frequency at 4300 * ,

i 100 volts and 60 1.2 Hz. Subsequently, verifying the || generator is synchronized, graduelly loaded to an indicated 3250- '

! 3350 kw and operates for at least 60 minutes.t

, e

| 5. Verify that the AAC DG total battery terminal voltage is greater;j than or equal to 126 volts on a float charge before initiating '

| Surveillance Requirement 4.8.1.1.2.f when operating in Modesi 1,2,3 or 4.

I

j 6. Verify that the starting air tank is > 275 psig.!

7. Verifying that the following A.C. electrical buses are OPERABLE: I<

a. 4160 v bus OM

b. 4160 v bus OL ],

c. 480 v bus OM1

! d. 480 v bus OM1-1'

; :

'

28

.

- -

- . - . -- . - . - . . - - -- -- -

i |i i

|6.0 CONCLUSIONS :

r

~

Virginia Power has performed an analysis of extended EDG outages. The analysis ;

included an update of the existing PSA model in order to keep it current with the !

configuration of the plant. A base case was run with and without the AAC DG model,

activated assuming the current average annual unavailability for the EDGs. The core

| damage frequency for the case without the AAC DG is 5.4E-5/yr while the base case! CDF with the AAC DG included is 4.1E-5/yr as reported in Table 3.2. When the! unavailability of each EDG is increased to include a single 14-day outage once every !

18 months the core damage frequency increases to 4.2E-5/yr. A sensitivity analysis! performed with even larger assumed EDG unavailability shows that the increase in

;CDF is still much less than the decrease resulting from the addition of the AAC DG.,

The decrease in core damage frequency associated with adding the AAC DG is 1.3E- ,

5/yr while the increase in CDF resulting from the increased EDG unavailability is 1E-4

! 6/yr. This increase in CDF is small and meets the criterion for acceptable risk increase ;

identified for this project.

The PSA analysis found that the increase in CDF with the additional EDG unavailabilityi is small. The analysis considered operation in Modes 1 and 2. Administrative

.

| procedures preclude performance of the EDG inspection outage coincident with a !; planned transient. Continued performance of the inspection outage during unplanned

entrance into Modes 3 and 4 was evaluated and found to be acceptable as long as;

; secondary heat removal capability could be demonstrated.!; With the EDG maintenance performed on-line it is not expected to be necessary to |; have an EDG in extended maintenance during shutdown conditions. Hence, any :

increase in risk associated with the inspection performed on-line is partially offset by,

the reduced risk of core damage during shutdown. Thus, the overall CDF increase is ;

j less than the 1 E-6/yr identified above because the units will typically have both diesels j

in operation for most of the outage. This means that both EDG's will have higher !'

availability during loss of off-site power events at shutdown, which will improve

} residual heat removal system availability in these events. In the past, one diesel was ideclared inoperable for about half of an outage. Therefore, for half of the outage

i decay heat removal during loss of off-site power events is highly dependent upon a ;

single RHR pump; the redundant RHR pump is available only if powered by the AACDG.

:

: A shutdown PSA has not been performed for North Anna. However, a shutdown PSA| analysis was performed for Surry Power Station that is documented in NUREG/CR- ,

614452. The Surry shutdown PSA found only reduced inventory plant operational i<

j< ,

J 12" Evaluation of Potential Severe Accidents During Low Powerand Shutdown Operations at Surry, Unit 1 - Analysis of Core Damage

~

j Frequency from Internal Events During Mid-Loop Operations,"' ij 29 '

|

!|1

|

. - _ _ _ _ . _ _ _ _ - - _ _ _ _ _ _ - - - _ _ _ _ _ - _ - _ _ _ _ _ _ _ - _ _ _ _ _ . _- - - - . - - - - .-

_ _ _ _ _ _ _ _ _ _ _. . . _ .-. _ ..- __ _ _ _ _ . . _ _ .

states were significant contributors to core damage frequency. The study also foundthat " maintenance unavailability was the dominant cause of equipment unavailability"during the reduced inventory states. In this study the EDGs were defined to be partof the minimum equipment list for reduced inventory situations so they were assignedno maintenance unavailability.

The above shutdown PSA model was used along with a full power PSA model to lookspecifically at the impact of EDG maintenance at power and during shutdown. Theresults of the comparison are reported in NUREG/CR-5994'8 prepared by Brookhaven ;

National Laboratory. This study shows that the change in CDF due to an EDG being :

in maintenance is the same as or more significant during most shutdown operational j

configurations than when the EDG maintenance is performed at power. While thisconclusion indicates that EDG maintenance at power is risk beneficial it should beremembered that Surry has only three diesels and that the North Anna model ,

presented herein takes credit for five diesels. The impact of the AAC DG at shutdown !

could change the results of the Brookhaven study. Nevertheless, this study confirms ;that some shutdown risk is averted by doing the maintenance at power.

,

Based on these results Virginia Power concludes that it is acceptable to conduct the18 month EDG preventive maintenance and inspection during any mode, and duringmode changes, as long as the inspection is performed in a single 14-day EDG outage ;

once every eighteen months and the AAC DG is operable during this time. -

I

Restrictions on the operability of other equipment are also defined. The 1E-6/yrincrease in CDF calculated as a result of the increased EDG unavailability meets thecriterion for acceptable risk increase defined for this project.

:

>.

! !

! !

! t*

i

!

! !-.

!

!

!

NUREG/CR-6144, Executive Summary, pp xxxii-xxxiii, June 1994.

j "" Emergency Diesel Generator: Maintenance and Failurei Unavailability, and Their Risk Impacts," NUREG/CR-5994, Chapter 5,! November 1994.!

30'

|;

I,

!

__ _ - - _ . - - . . _ ,

-

:

APPENDIX A |

Fault Trees I

The following fault trees are contained in this Appendix.

1D_ Name Descriotion1EG 1EG Emergency Diesel Generators Unit 16/95 PSA,1 p.

2EG 2EG Emergency Diesel Generators Unit 2 6/95 PSA,1 p. )|

AAC OAAC Alternate AC Power Units 1 & 2 6/95 PSA,1 p. ||

DAM DAM Disallowed Maintenance Unit 16/95 PSA,19 pp. ;

E1H E1HOO 1H Emergency Electric Power Unit 16/95 PSA,15 pp.

E1J E1JOO 1J Emergency Electric Power Unit 16/95 PSA,12 pp.

E2H E2HOO 2H Emergency Electric Power Unit 2 6/95 PSA,13 pp.

E2J E2JOO 2J Emergency Electric Power Unit 2 6/95 PSA,12 pp..

ESY ESYOO Switchyard Buses Units 1 & 2 6/95 PSA,14 pp.

FFT FFT Functional Fault Tree Unit 16/95 PSA,6 pp.

LR1 LR100 Low Head Safety Recirculation Unit 16/95 PSA,10 pp.

T9A lET9A T9A Loss of 1H 4160 Elect Pwr Unit 16/95 PSA,1 p.;

T9B IET9A T9A Loss of 1J 4160 Elect Pwr Unit 1,6/95 PSA,1 p.,

|

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o | t i 2 1 3 4 d 4 5|

semesoner esen_

%,,.,,, Eserpency D12sel genentors.-

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Fall 510 ILDE SpWIIgugLY OPEss $4Y-e-1| I. ESEG130 SEESKA-FO-tSee IEESKA-SO-SSpe IEESAT-LP-3 .

jayo !a.se ens s.sm ess a t. amass as

-I 1 .!i EDGs set SJ pt 2J 'CtesEN Ca4M FaiLTS CINedpf Cam Fa4Lf8

Common tause faulte EINE $N ase sJ SATTEltIn 3 07-6-3 {j I ase s-ev-0-3

61Est3D sE9EOG-CC-t*-tJ SEESA1-CC-I-IIIt.EE*ea s eEE eOS

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Geneester $J9-EE-EG-$J

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7 NtpensLLY * OFAILS TO Stast? 10 sase FOR 6 sosis emovetteettityGtEGIFO XHD5-06- tJ4a lL$~ 1EGEDG48-lJ SEGEDG44-1J tEGEDG-fet-tJ0.edE400 4.G est 8.3E40f 6 3.M-e88

I"

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0 | 1 | 2 1 3 1 4 1 5

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L

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FAILS TO Q.tX asse vk G2EGt20 3EEDA40-25 2 3EESKA-50-3 WP SEESAT tP-I!!

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o I t I a i 3 1 4 1 5 |1

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s.es-ear esses s.est ess

""1 I Ii IFAILifE F sgace

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f i,34 g# gags ase OGL43670

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seOSA Afe see5C Ceemen Cause Faulte '

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{'Llett Betten LS4

ISIL8tS-LF-10BSA GLR 40Sd ERISSd is! M -t mg g gim se, i.am se.,

. .

3- . - _ . .-. _ . - - _ _ -_ . - _ - _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ .

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TO CLDE Te CLIKi 5' etn, 5, etnisse

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i ator mCC sJa-2NGS Felle enen seat auteeststelly 400 y SCC ems-25 Falls seen set Amstemottently!

6 O= senuell, amenee 9" tienuelly Denes ;

setastsa tslisov-Fo-888SD EA1862 Gestes 412 1sleev4 0-1885A ELA1006i

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1 Low Head Sefity Retir*CU): tioni NAPS Urtit 1! O '

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F1unt LME1 Teatu e Flust Last 1malN A ?,

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D!vtEION NfW FLSW CpffAlastaff mass.

3ieLRisso eLASSIP GLRiddl SLAIE3d E RISSI

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e.est eese 1.ver-ess 8.ast-eas saide

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FatufE F sang FalusE F seeBCi TO CLON TO CLOK1

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as0 ELECTA!C FouER l-51-cov-seest 1-53-sOF-18850 le to ELECTRIC FouER i-SI-upplenBC 1-51-8EDW50MC le |; deov seCC SJi-PdSS Felle Open set autenetstelly 400 V IEC $Mi-25 Felle Open let Auteeststelly I; te annually esenesi 6 or senuelly esenes '

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ii

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8.85 987 5. abet

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Leelt Seiten LS-g ets3DA AAC R$d7A Llett briten LS-lOGS3tP9dd ISIMDV4C-10SN ISILeIS-LF-SSS M 9 95112912 SSIfOV4C-SM 3A IS! Lee-LF-stS3ai n, sisse s.seE cor 3. ggt.een s seo 3.e0E-est 8.2EEaeed

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Low Hs 0 Safety Ancir'culatitri4n'NAPS Unit 1 ' S/95 PSA =v

afuaLYST: Isf | M4130N haft 06-3D-1988 ' EVISIO4 : 06-01-95'

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Common Cause Foulte C - . .eConson Cause Faulte, 151CRv-CC*P06207 ISICatW4C-sos eLR11072 ISICMV-CC-206207 SSICKv4C-207 eLR180786.M 485 8.M-end

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| APPENDIX Bj Event Trees |

'

!

!4

'.

! A: Large Break Loss of Coolant Accident (LOCA); AD2: Large Break Loss of Coolant Accident (LOCA) & Accumulators Fall To !| Inject '

j

j

Rx: Reactor Vessel Rupture f!;

: S1: Medium Break Loss Of Coolant Accident i

| S1D1: Medium Break Loss Of Coolant Accident (LOCA) Without High Head !!

| Safety injection

*,

S2: Small Break Loss Of Coolant Accident (LOCA)S2D1: Small Break Loss Of Coolant Accident (LOCA) Without High Head Safety ;

;

! Injection ;

i:

}

| T1: Loss Of Off-site Power ;

j T1EE: Unit 1 Station Blackout Loss Of Off-site Power & Failure of Unit 1 i

j Emergency Diesel Generators And Alternate AC Diesel |: T1EEQ: Station Blackout (Loss Of Off-site Power & Failure of Diesels to Supply| Power) And Pressurizer PORV Fails Openi T1Hv: Loss Of Off-site Power & Loss Of Emergency Switchgear Room Coolingi T10: Loss Of Off-site Power & Pressurizer PORV Fails Open! T10AFW: Loss Of Off-site Power & Pressurizer PORV Fails Open & Auxiliary

Feedwater Fails,

i

i

{ T2: Loss Of Main Feedwateri T2A: Recoverable Loss Of Main Feedwater| T2AHv: Recoverable Loss Of Main Feedwater & Loss Of Emergency Switchgear

1

i Room Cooling '

4 T2Hv: Loss Of Main Feedwater & Loss Of Emergency Switchgear Room CoolingT3: Transients With Main FeedwaterT3Hv: Transients With Main Feedwater & Without Emergency Switchgear Room

Cooling

i

T4: Loss Of Reactor Coolant Pump Seal Cooling,

1

T5A: Loss Of Emergency Power DC Bus 1-1'

T5AQ: Loss Of Emergency Power DC Bus 1-1 & Pressurizer PORV Fails OpenT5B: Loss Of Emergency Power DC Bus 1-|||

.

_ _ - _ _ _ _ _ _ - _ - - - _ _ - - _ _ _ - - - _ . - _ _ ' _ _ _ _ _ _ = + _ - - m q r

-

TSBQ: Loss Of Em:rg:ncy Powar DC Bus 1-Ill & Prcssurizer PORV Fcils Op:n

T6: Loss Of Service Water

T7: Steam Generator Tube RuptureT7D1: Steam Generator Tube Rupture Without High Head Safety injection

~

T8: Loss Of Emergency Switchgear Room Cooling

T9A: Loss Of Emergency Power 4160 V Bus 1HT9AHv: Loss Of Emergency Power 4160 V Bus 1H & Loss Of Emergency

Switchgear Room CoolingT9AQ: Loss Of Emergency Power 4160 V Bus 1H & Pressurizer PORV Falls

OpenT9B: Loss Of Emergency Power 4160 V Bus 1HT9BHv: Loss Of Emergency Power 4160 V Bus 1H & Loss Of Emergency

Switchgear Room CoolingT980: Loss Of Emergency Power 4160 V Bus 1H & Pressurizer PORV Fails

Open

TH: Anticipated Transient Without a Scram ( ATWS) When Greater Than 40%4

Reactor PowerTHMFW: Anticipated Transient Without a Scram ( ATWS) When Greater Than 40%

Reactor Power & No Main Feedwater,

TL: Anticipated Transient Without a Scram (ATWS) When Greater Than 40%4

Reactor Power

Vx: Interfacing System LOCA ',

|

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