ML20092A261

EDG Preventive Maint Insp Outage Probabilistic Safety Assessment for August 1995

ML20092A261
Person / Time
Site:	North Anna
Issue date:	08/31/1995
From:	VIRGINIA POWER (VIRGINIA ELECTRIC & POWER CO.)
To:
Shared Package
ML20092A247	List: ML20092A242 ML20092A248 ML20092A261
References
NUDOCS 9509080288
Download: ML20092A261 (177)

Text

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1 Attachment 4 i

O l North Anna Power Station Units 1 and 2 l Emergency Diesel Generator l Preventive Maintenance inspection Outage PROBABILISTIC SAFETY ASSESSMENT I

August 1995 VIRGINIA ELECTRIC AND POWER COMPANY d

95090B0288 950901 PDR ADOCK 05000338 P PDR

i TABLE OF CONTENTS

1.0 INTRODUCTION

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2.0 BACKGROUND

INFORMATION ............................. 4 2.1 Emergency Diesel Generator . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 2.2 Emergency Electrical Power System ..................... 7 2.3 Alterna te A.C. Die sel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 3.0 PSA A N ALYSI S . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 3.1 Comparison to IPE model . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 3

3.2 Revised EDG Unavailability Data . . . . . . . . . . . . . . . . . . . . . . . 16 2

3.3 A A C DG TM . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 3.4 AAC DG Base Case . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17 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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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APPENDIX A: Fault Trees APPENDIX B: Event Trees i

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1.0 INTRODUCTION

1 This report was prepared to document the feasibility of a 14-day outage on-line 4 (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 on i

this conclusion, a request for revised North Anna Power Station Technical 9 Specifications associated with EDG outage time is being proposed. This report is being prepared to serve as an attachment to the licensing package.

Section 2 presents background information on the reason for the request and a summary 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 provided j 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  !

l shutdown conditions as required by Technical Specifications. Because the inspections require at least ten days to complete, a significant burden is placed on the maintenance crews to perform this work along with the many other tasks that must

, be performed during an outage.

l l Virginia Power has determined that the substantial benefits of performing this i maintenance on-line justify the negligible increase in risk for at-power conditions because of the decrease in risk achieved due:

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> to installation of the AAC DG, j > to improved maintenance quality resulting from focused resources on the j EDG maintenance, and l > to 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 power distribution 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 emergency I

bus.

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2.1 Emergency Diesel Generator The Emergency Generator (EG) System provides a reliable source of emergency electric power to Engineered Safeguards Features (ESFs) and other essential loads in '

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 EDG independently powers a train of safety-related equipment, thereby providing redundancy in the event of loss of an EDG. Each EDG in a unit will automatically start when a safety injection signal from its associated train is present. Each EDG in a unit will automatically start with a pre-set time delay upon sensing either undervoltage or degraded 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 emergency bus if the residual voltage on the bus is less than 30 percent, a degraded or undervoltage exists, the 4kV buses are aligned properly, the EDG volts are greater than 95 percent, and the EDG output breaker lock-out and EDG differential breaker relay are reset. Each EDG is initiated automatically or manually and consists of a diesel engine, governor, generator with excitation system, controls, battery and charger, and the following subsystems: starting air, fuel oil, scavenging air and exhaust, lubricating oi!, Jacket cooling, and air cooling.

The diesel engine provides sufficient mechanical power to drive a generator with a 2,000 hr/yr rating of not less than 3,000kW, both mounted on a sub-base. The governor is furnished with an adjustable speed droop, load limit, and remote speed control for 125V de operation The EG System may be operated from the Main Control Room or from the Diesel Generator Rooms. Control circuits are provided for local and remote operation of the engine, generator and generator output breakers. The engine initiation signals are provided 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,60 cycles. The generator uses a brushless exciter and rectifier assembly to provide excitation to the main generator field. Space heaters are provided for insulation protection.

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 air starting solenoids, and providing power for EDG control circuits voltage regulation and  !

protective relays.

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

document " Emergency Diesel Generator System, North Anna Power Station," SDBD-NAPS-EG, Rev. 1, Section 3.1, 12/31/93 4

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

Each starting air train has an air receiver (tank) that stores a sufficient voleme of compressed air to provide five diesel engine starts without recharge. Each air receiver is kept charged by an electric motor-driven air compressor powered from the Emergency Electrical Power (EE) System. Each compressor has a small diesel engine backup 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 transfer pumps, and engine delivery and injection components. The fuel oil is stored in two safety-related underground fuel oil storage tanks (one per unit) which contain sufficient capacity to provide continuous operation of one EDG in each unit at fullload for 7 days. The underground fuel oil storage tanks are filled from the aboveground non-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 fuel oil storage tanks, and one standby fuel oil transfer pump takes suction from the other '

tank. Either transfer pump fills and maintains the proper level of the day tank required for diesel generator operation. The day tank has sufficient capacity to support a fully loaded engine for at least 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />.

The scavenging air and exhaust subsystem provides pressurized air to the diesel engine 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 standby circulating pump. This subsystem provides cleaned and cooled lube oil to the diesel engine and its components during operation.

The air-cooling subsystem consists of an engine-driven pump, a three-way mixing valve, radiators, and aircoolers (aftercooler). This subsystem removes heat from the combustion air in the scavenging air and exhaust subsystem. A three-way mixing valve controls the flow through the radiators. During EDG operation, an engine-driven air cooling pump circulates cooling water through the radiators for cooling and then to the aftercoolers in the scavenging air and exhaust subsystem. Cooling water is also circulated through the radiator fan gear box cooler. The radiator fan assembly provides forced air flow over the radiators in both the jacket cooling and air cooling subsystems by drawing ambient air into the Diesel Generator Room, over the radiator fins, and exhausting through the roof.

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l 2.2 Emergency Electrical Power System The Emergency Electrical Power (EE) System provides a highly reliable power source

! to Class 1E loads and certain non-Class 1E loads during all plant conditions2 . Figures 1 and 2 show one line diagrams of the emergency buses for Unit 1 and Unit 2 i 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 is referred to as the train B (purple; J) system. Each EE System train consists of a 4160V switchgear, two 480V load centers, and 480V MCCs, which supply power to motors, motor-operated valves (MOVs), heaters, lighting, and other loads, which are required to be powered during normal and design basis event plant operating conditions.

Each train is normally energized continuously from the switchyard external grid system. This preferred power supply is available from the reserve station service transformers (RSSTs) via the transfer buses. Upon loss of the switchyard " preferred 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 per unit. Each 100-percent capacity EDG is connected to its assigned train and is 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 to the 1B bus. The 1B bus may be energized in the startup or shutdown mode from RSST B (Figure 1). In addition, if the main generator breaker is open, the 1H bus may be supplied through the main transformer, the unit station service transformer, and the 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 is operating, is from RSST B.

An additional off-site source of Unit 2 normal station service power can be made available in 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> by removing the isolated bus duct disconnect links, backfeeding 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 emergency bus 1J for Unit 1. To minimize low-voltage effects on equipment during an EE System emergency bus transfer from the off-site source to the diesel generators, the 4.16kV Class 1E bus is divided into two sections: the normal Class 1E bus section and the stub bus section, which are connected via the stub bus tie breaker. The stub bus section supplies the component cooling and residual heat removal loads, which are not immediately required during an accident condition. These loads on the stub 2

The information in this section is taken from the SDBD document " 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 1

. For Unit 2, either 4160V emergency bus may be connected to the emergency bus of l 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 2.3 Alternate A.C. Diesel i

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 be j capable of a "2000" hour rating of 3640 kilowatts.  ;

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

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 an i automatic process with pump and valve activation based on tank level. Additionally, j a gravity fed bypass of the pump is available.

l The AAC DG can be started by local operator action or by receiving an auto start i

signal following the simultaneous loss of the D or E and F transfer buses. This logic  ;

l will prevent unnecessary diesel starts when a single emergency bus is lost (one RSST) I i

i on a unit, while providing a diesel start when the potential exists for a station blackout l (i.e., loss of both emergency buses on a unit). After it has started, the diesel will be '

i available for manualloading onto the desired transfer bus and subsequent emergency i 1

bus as shown in Figure 1 and Figure 2 for Unit 1 and Unit 2 respectively. l i

l 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 i i

a J bus in order to deal with a station blackout. Therefore, if the H EDG is providing l 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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i Figure 1 - Power Supply to 1H and 1J Emergency Buses 8

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1 Before Station Blackout (SBO) modifications were made the normal off-site feeder breakers from the transfer buses to the emergency buses (15D3,15E3,15F3 and 15F4) were tripped and blocked from closing following a loss of off-site power, a RSST differential trip, a pilot wire trip or a trip of their associated main transfer bus breaker (15D1,15E1 or 15F1). These non-safety related breakers, however, must be closed during a SBO with any or all of the mentioned conditions present. This has been accomplished by adding a " NORMAL /AAC" switch on the AAC breaker control panel for each breaker (15D3,15E3,15F3,15F4). In the "AAC" position, this switch will bypass / defeat the trip and close interlocks stated above. Once the transfer bus breaker is closed, the associated emergency bus breaker may be closed and the desired 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 the D and E versus the F transfer bus system and its feeders have been maintained. The new switchgear provides isolation of the AAC source from the normally energized transfer buses. This arrangement also minimizes the increase in exposure of the energized transfer buses during normal operation by maintaining them in their associated Switchgear Room.

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

A bus relaying panelis located adjacent to the diesel generator monitoring panel. This panelis supplied by the switchgear manufacturer. The panel contains the generator l protection relaying. There is also a control panel installed adjacent to the diesel generator control panels which provides remote control of the new AAC system breakers. These breakers were added to provide the electrical connection between the 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 and inspection appropriate for diesels used for this class of standby service. This l maintenance involves disassembly of the major subsystems in order to clean and inspect components. A list of the components which are included follows:

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inspection Covers and Exhaust Manifold Crankshaft Coupler Pointer Check Crank Leak Check Fuel injection Timing Check inspection of Fuel Oil Pump Shaft Seal inspection of Governor and Fuel Pump Drive inspection of Lube Oil Pump and Coolant Pump Drive Gears inspection of Upper Torsional Dampers Inspection of Lower Torsional Dampers inspection of Lube OilInternal Piping inspection of Pistons, Rings, and Cylinder Liners Inspection of Blower Flexible Drive, Timing Gears and Spring Packs inspection of Timing Chain, Sprocket and Sprocket Bearing Measuring Lower Crankshaft Strain on Cylinders No.11 and 12 Upper and Lower Main and Connecting Rod Bearing inspection inspection of Vertical Drive Shaft Gears and Coupling Checking Crankshaft Thrust Bearing Clearance Checking Torque of Crankshaft Coupling Bolts Fuelinjection Nozzle Opening Pressure Check and Seal Leakage Check

, Air-Start Check Valve and Distributor inspection Inspection of Cooling Water Side of Lube Oil Cooler Engine Block Coolant Hydrostatic Test Cleaning and inspection of Crankcase Assembly and Cleaning Oil separator / Breather Lube Oil System Maintenance i Fuel Oil Day Tank Foot Valve Strainer Maintenance

Changing Oil in Woodward EG-B10 Governor Blower Lobe and Housing Clearances Blower inlet Air Filter inspection Installing Exhaust Manifold and Engine inspection Covers Cleaning Standby Lube Oil Heater Refilling 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 list of activities requires about fourteen days to complete in the worst case. On average it takes about ten days to perform this work (i.e., with no unplanned additional activities).

Two crews work to support the EDG maintenance. Obviously, this represents a cost that will be incurred regardless of when the dieselis maintained. However,if the EDG inspection can be performed when the unit is on-line, the crews doing this 11

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l maintenance can work on other outage activities during refueling operations. So, more of the outage work can be performed by Virginia Power personnel. This action represents a cost savings because there are fewer contractor personnel required. in addition it is estimated that one day of critical outage time can be realized using this 1 approach.

3.0 PSA ANALYSIS The PSA analysis was performed with a model of North Anna that represents the current operation of the station. The IPEEE model was upgraded and enhanced, including use of the newest version of NUPRA8 . Each stage of the development is 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 for additional information (RAl) was received and the response was submitted on April J

28,1995. 5The IPEEE model, submitted in June 1994', is similar to the IPE model but 3"NUPRA 2.2 Users Manual," NUS Corporation, March 1994.

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

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

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

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

There are significantly more event trees listed for the IPEEE than the IPE. The number of accident initiators remains the same in both models. The original event trees were spiit into smaller trees with less sequences to improve the utility of the two trees. For example, by splitting the large LOCA tree into two the number of sequences on each page is cut in half and therefore is much easier to read. The accident sequence structure did not change for most accident initiators. However, as mentioned above the structure of the T4, T6 and T8 trees were changed. Each of these trees is discussed 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. Following the IPE solution, it was evident that this depressurization assumption did not significantly 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 seal cooling is mitigated using the core cooling recovery strategy given in the emergency response guidelines. The T4 contribution to core damage frequency doubles, relative l to the IPE, to ~ 2E-8/yr. Hence the change is not significant but represents consistent seal LOCA modeling among the event trees.  !

The loss of service water tree (T6) was changed more substantially. Given the loss i of 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 be found. Fortunately, another heat sink is available for each component. The use of

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

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{ these alternate heat sinks was developed to support the large service water pipe restoration 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 seals but 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 noted that the absolute value is still quite small at about 0.9% of total core damage  :

frequency.  ;

The final tree with structural changes is the loss of emergency switchgear room cooling event tree (T8). Once the event occurs it is not an issue of depressurization as much as it is one of needing to provide alternate RC pump seal cooling before it is lost. Since the T8 initiating event affects only one unit, the equipment on the unaffected unit is available to mitigate the loss of seal cooling. Therefore, the tree has 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 ,

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! injection and seal cooling to the affected unit. As a result of these changes the lots of ESGR cooling initiating event contributes ~ 6E-7/yr to CDF as opposed to ~ 7E-6/yr using the IPE model.

The core damage frequency was nearly the same for both solutions. The IPE core damage 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 to be non significant based on a comparison of the cut sets for each function. Some of the IPEEE event trees were used in the analysis of fires as reported in the Non-Seismic IPEEE final report7.

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

have improved. One significant advancement is that NUPRA now allows batch mode solution 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 same as the previous results or that any differences are understood. The EDG-TM run l

served this purpose, i

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

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

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transfers from the earlier models were deleted; and two new functions were added to the T1 event tree, providing status of the Unit 1 and Unit 2 EDGs, to facilitate development of the AAC model. The core damage frequency for the IPEEE modelis 6.3E-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 and maintenance 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 l 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 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br /> per EDG per i 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). l 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 EDG unavailability with the EDG exposure yields en unavailability probability of 1.28E-2.  ;

This can be expressed in terms of hours as 112.2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> / 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. j Furthermore, 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 is i

accomplished by determining how many hours of diesel unavailability there are when  ;

the unit is in Modes 3 to 6 and adding that to the diesel unavailability during Modes 1 and 2. '

Based on a review of available data and discussions with plant personnel it was I concluded that the total unavailability per diesel is conservatively estimated to have l 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) = 15.3 3

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

t l

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 l

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

p 15 /

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

l l

}

' l 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 about the 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

! 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 Technical i 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 l 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 EDG j unavailability by a factor of two.

I j 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.

l Therefore, it is postulated that this AAC DG can serve as a replacement to the EDG j 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 of i hours of maintenance unavailability.

i r

it should be noted that this diesel can not serve as a replacement for an EDG for all i

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 as i 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 determine which 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 power available including: Large LOCA (A); Medium LOCA (S1); Reactor Vessel Rupture (Rx); interfacing system LOCA; and ATWS (Th). The assumption that AAC DG cannot mitigate core damage for these initiating events is executed by special PSA model logic.

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

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

The addition of the fifth diesel to the PSA model complicates the EDG common cause model. First, the criterion for the purchase and installation of the AAC DG was to minimize 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 four diesel common cause failure is not straightforward. Third, the IPE utilizes the multiple greek letter method for EDG common cause failures, and this 11 fault model could become unwieldy with an additional diesel. The 95 JUNE PSA solution chose to simplify the EDG common cause model in a conservative manner, reducing the 11 fault model to a 3 fault model. Two faults are unchanged, the Unit 1 two EDG fault for 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 faults are combined with the four EDG common cause fault. This approach is conservative and ailocates the common cause failures among the two units.

The system model for the AAC DG is similar to EDG model. It considers the typical electrical equipment failures that prevent the transfer of electrical energy to each of the three transfer buses. These failures include breaker failures, maintenance unavailability, AAC DG fail-to-start and fail-to-run. The fault tree resulting from the system modelis shown in Appendix A.

The addition of the AAC DG reduces core damage by requiring three failures, instead of two, to fail both 4160 V electrical buses after a loss of off-site power. The 95 JUNE model represents the current plant hardware configuration, and with the addition of the AAC DG, the core damage frequency is reduced by ~1.3E-5/yr to 4.1E-5/yr compared to the NO-AAC model shown in Table 3.2.

1 17 l

3.5 Extended EDG Unavailability For the EDG-AOT model, the EDG unavailability is increased to reflect the assumption of a single, fourteen day maintenance outage once every eighteen months for each EDG. Actually, the 95 JUNE model data is applied to the EDG-AOT model, except for the Unit 1 EDG maintenance unavailability basic events. The 14 day preventive maintenance and inspection outage time is added to the existing unavailability to determine the impact of the proposed EDG Technical Specifications changes. A 14 day outage performed once every 18 months is equivalent to 9.3 outage days, or 224 hours0.00259 days <br />0.0622 hours <br />3.703704e-4 weeks <br />8.5232e-5 months <br />, per calendar year. Adding this unavailability to the 97.30 hour3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br /> plant data unavailability of yields a total unavailability of about 321.3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />. Combining this 321.3 hour3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> unavailability with the 7601.66 cr-hrs per calendar year exposure produces a new unavailability probability of 4.23E-2.

The EDG-AOT model solution yields a core damage frequency of 4.2E-5/yr. The 95 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. This model is . named " BOUNDING", and represents a sensitivity study on EDG  :

unavailability. The maintenance unavailability was set equal to 40 days per calendar year 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 shown in Table 3.2. The CDF contribution from the each initiating event is shown in Table 3.3. Table 3.3 is a listing of core damage frequency sorted by accident group and accident type. The fault trees which have been changed since the IPEEE model was created are included in Appendix A. The event trees for the 95 JUNE model are included in Attachment B. The results show that the electrical transient accident initiators are sensitive to the inclusion of the AAC DG and to varying the EDG unavailability. Other accident initiators are less sensitive to the AAC DG and EDG unavailability.

The LOCA transients shown in Table 3.3 contribute the same to core damage frequency 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 not impact the contribution of this initiating event group. The same conclusion can be drawn for the general transient group of initiating events. The electrical transients are 18 l

J impacted by both the AAC DG and the increased EDG unavailability. The inclusion of j 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 involving loss of electrical power and include the T1 and T1EE trees. These trees have in 4 common the loss of off-site power as an initiating event. This fact makes the diesel  !

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

power must occur before any diesel dependencies are realized. Unless the initiating

, event 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 on j Unit 1; or in other words a unit blackout. This event tree is the largest contributor to l core damage until the AAC DG is added to the model. The AAC DG decreases the i 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 this i 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 i

of replacement power for an EDG for the limited outage required to perform the 18-month inspection.

i The PSA models assume that other risk significant equipment is unavailable on an average 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. This

, important consideration is ensured by the administrative controls in place for i performing on-line maintenance. These controls are based on a list of risk significant equipment 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 risk j significant equipment. Special emphasis is given to limiting on-line maintenance when j the electrical distribution system is at less than full capacity.

J e

d 19 1

l 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

)

Medium LOCA S1 S1,SID1 1

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 l l

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 l

Interfacing System LOCA VX VX 1 ls i l

l l

4 l

) 1 1

20 -

1i 5- 5- 5- 5- 5 5- 5-by Fr E E E E E E E Cl 8 3 7 4 1 2 7 6 6 5 5 4 4 4

_G D A A A 3 3 3 0

/ / /

.C N N N 7 7 7 0 A 1 1 1 4 r

a e

A Y

r e

d e

n

- l a  ;

C 2' 7 7 7 3 3 3 0 s r e

tG k iDn 1 1 1 7 7 7 0 -

u P UE 3 3 3 1 1 1 4 -

s s -

e y -

R a -

f D -

O e y g r

a t a

m u 1 m O i 2 u t G 5 5 5 1 1 4 0 S iD n E 3 0

- 5 5 5 4 4 U 1 4

'2 '

3 l

e b

a T

G ~o DN/ o o o o s s s Cs N N N N e e e Ae Y Y Y AY e

m T G a E M C A E

N O N N

I E E T- A- D P E A- U N l

e I P G J G d I D O 5 D U o E N 9 E O M B ll llf

. Table 3.3 '

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

Accident IAccident ' . 94 Jan D - 92 Dec Group 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-6 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-6 Vx 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-7 T4 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 l

l

[

k 22

Table 3.3

~ Core Damage Frequency For Each Accident Group For Each North Anna PSA Model Accident  : Accident ' 94 Jan - 92 Dec Group - 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-7 T3Hy 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 l

24

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

4.0 ACCEPTABLE RISK INCREASES Virginia Power has determined what constitutes an acceptable risk increase for the proposed Technical Specifications changes. This determination was based on a review of existing documents and the selection of the guidelines most applicable to North Anna Power Station. The pertinent documents are summarized below.

The EPRI PSA applications guide discusses the concept of a permanent modification which is essentially what is proposed herein. The modification is to the Technical Specifications not the plant hardware. The EPRI document states that a permanent risk increase can be determined as a percentage of the base CDF. The calculation for North Anna follows assuming that the base case is the IPE model submitted previously for NRC review.

log ( A,) =-0. 5

• log (CDFw%) -1 For North Anna the baseline core damage frequency (CDF%)is 6.8E-5/yr. So, the acceptable 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 base 10 gives -

A ,=12.1 h

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

l from the largest initiating event categories. It is larger than the largest contribution l 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 l 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 acceptability of sensitivity analysis is if the overall equation has minimal cut sets for the down component 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 '

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

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

25

l acceptable risk increase criterion is 1.0% of the base core damage frequency which for 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 types of cutoffs that have been chosen in other applications. For example, the reporting guidelines for the individual plant examination require core damage sequences greater than 1E-7 per year and within the upper 95 percent of the total core damage frequency to be reported. The NUMARC guidelines for the maintenance rule define risk significant components in several possible ways'. One way is the use of the core damage frequency contribution. Cut sets that account for about 90% of the overall core damage frequency, with appropriate eliminations, should be used as input to risk determination. Since a cut set can appear in only one sequence this is the same as a sequence requirement and is obviously less restrictive than the 1% number discussed 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 frequency as indicated by the North Anna IPE.

As a result of the above discussion it is clear that the use of something on the order of 1% as an acceptable risk increase is within the bounds used by NRC and its contractors for PSA applications. It is also clear that it is more conservative than some 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 the evaluation of the extended EDG outage.

5.0 IMPLEMENTATION REQUIREMENTS An implementation plan is necessary to ensure that analysis assumptions are properly incorporated into station operating procedures. The plan presented below has two components: equipment required to be operable during the extended EDG maintenance outage and other safety related equipment potentially available for on-line maintenance.

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

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

" Procedural and Submittal Guidance for the Individual Plant Examination of External Events (IPEEE) for Severe Accident Vulnerabilities - 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 defined in the Technical Requirements Manual. Operability includes the EDG set and several subsystems, such as the fuel transfer system, in a manner similar to the EDGs. '

Surveillance requirements have been defined for these AAC DG subsystems and some specific components. The AAC DG operability items are listed in Table 5.1. In addition to these operability requirements in Table 5 the AAC DG must be tested within 14 prior to removal of an EDG for its preventive maintenance inspection outage. During this testing the AAC DG must be aligned to the transfer bus associated 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 breaker position for providing power to each bus. The procedure should include an equipment load 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 preventive maintenance during the fourteen day extended outage is governed by existing on-line maintenance administrative controls which rely on a list of risk significant equipment developed from the North Anna PSA model. The administrative controls currently require that only one functional equipment group, FEG, (i.e., all of the subcomponents which must function in order for a major piece of equipment to function) be unavailable for planned maintenance at the same time.

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

The performance of this inspection outage during modes 3 and 4 has not been specifically analyzed. The at-power PSA model is not appropriate for these conditions. NUREG/CR-5994" considered the effect of EDG maintenance on core damage frequency during various modes of operation. The study concludes that EDG maintenance 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 l

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

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

27

i i

t 4

modes while the EDG maintenance is in progress, the increase in core damage i frequency resulting solely from changing modes does not require continued cooldown as long as sufficient secondary heat removal capability exists. Sufficient secondary heat 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 EDG i 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 I 3

. ' yTablel5.1} . . . ..

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 oil j 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 l l feed flow to the day tank is > 4 gpm, or verify gravity feed flow l l 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 l speed (900 rpm) with generator voltage and frequency at 4300 * ,

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

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

l 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 '

l Surveillance Requirement 4.8.1.1.2.f when operating in Modes i 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 l i i l

6.0 CONCLUSION

S  :

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 l 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- ,

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

! 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 unavailability i is small. The analysis considered operation in Modes 1 and 2. Administrative .

l 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 l

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 i declared 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 AAC DG.

A shutdown PSA has not been performed for North Anna. However, a shutdown PSA l 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 Power and Shutdown Operations at Surry, Unit 1 - Analysis of Core Damage j Frequency from Internal Events During Mid-Loop Operations,"

i j 29 '

l l

1 l

states were significant contributors to core damage frequency. The study also found that " maintenance unavailability was the dominant cause of equipment unavailability" during the reduced inventory states. In this study the EDGs were defined to be part of the minimum equipment list for reduced inventory situations so they were assigned no maintenance unavailability.

The above shutdown PSA model was used along with a full power PSA model to look specifically at the impact of EDG maintenance at power and during shutdown. The results 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 this conclusion indicates that EDG maintenance at power is risk beneficial it should be remembered 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 the 18 month EDG preventive maintenance and inspection during any mode, and during mode 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/yr increase in CDF calculated as a result of the increased EDG unavailability meets the criterion 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 Failure i Unavailability, and Their Risk Impacts," NUREG/CR-5994, Chapter 5,

! November 1994.

30 l

I

APPENDIX A l Fault Trees I The following fault trees are contained in this Appendix.

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

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

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

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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1 3 4 d 4 5 semesoner esen Eserpency D12sel genentors f.e -es-su e 4

O NAPS Unit 1 5/95 PSA U J GtEGt00 amaLv51

mi iest41:ee art: o!H o-os . atvis:si : oe-es-es I I I  !

. Ensa rvent a t 10 ssensper DIEnn. samuser 0:aEL Fast as su t-a46-tu scenarsi sa sa Enaten sw Fa:Ls test s assaienonce IEBtteLLY

• O l I 61EGtto Fa!L5 TD START 10 stse FOR $ fGSE latevelleellitt '

spes-00-sD*4 alls SEGEO M S-In SEGED W A-tM SEGEDG-Tu-SM t.emesse s.est ear t.aIE4sr 6 8.aN-est i -

I I I  :

f aulte Commen enEasta ssMr To tu ano tJ EDEs maser stMr eaTTrav t-1 falls

, Ens cumtr Massa Eps atttpVT anEanEn 70 BPPLY POIO I

Fall 510 ILDE SpWIIgugLY OPEss

$4Y-e-1 l . ESEG130 SEESKA-FO-tSee IEESKA-SO-SSpe IEESAT-LP-3 jayo a.se ens s.sm ess a

t. amass as I

1 i .!

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j I ase s-ev-0-3 61Est3D sE9EOG-CC-t*-tJ SEESA1-CC-I-III t.EE*ea s eEE eOS

CDmON CAM FaLLTS EN

. d EGEas-CC-au.

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Emergency Daesel Geneester $J 9-EE-EG-$J I b G1EGt60 I i i 1 MOUEE EVENT

• t TO E8SIDEeCY 01 EEL i Fa!L EDE SJ tsEsuBCY O! EEL t-EE-56 tJ SEIERATOR tJ KtEmaicA $J f alls NtpensLLY

• O Test $ ustatenance l 7 FAILS TO Stast?

GtEGIFO 10 sase FOR 6 sosis emovetteettity XHD5 tJ4a lL$~ 1EGEDG48-lJ SEGEDG44-1J tEGEDG-fet-tJ 0.edE400 4.G est 8.3E40f 6 3.M-e88 I

i I Foulte Common I MANEn the WEasci 3SA To $N and tJ EDEs ED$ CUTMff RsEANER e&T7Env s-!!! Fall 5 3pWt[(kgy (ptog TG 3ppLT pguER Fa3LS TO CLE i l0

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2EG 1 -

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• 110 E8EIMICT DIEEL teEMICT DIEEL ME45-2 FAIL RIE 3H EBERATWIJH EsERafWt De FAILS Test 8 Meletenente ecenaLLT

• O FAILS 70 START 70fasePet 8seRIE tenevelletilltv i I G3EGste arts-0G-3W4 AILS EGEntr46-'M E GEOG 4 b 3M EGEDG-786-3M ]

e.eIEm s.am ene s.am-ear a s.au-est j i I I

] Faulte Casmen OftasER 2Bre WEaflER 3De SATTERV 3-1 FAILS 1 To 3H ens 3J EDEs BOS SUTpVT WEasER WutallRELT Oftes TO SMLT80ER ,

j FAILS 10 CLM 4300 V 2-09 4 -1  ;

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i i i I HREE EVEsa . 3 to EsERKaCY DIENL E8EneDCT DIEEL P-EE 4D-3J FAIL EDS RJ EIERAfem 3J EEIERATOR 3J FAILS Test & seenntenance 3 spe* ALLY = 0 FAILS TO Stant 70 RLos FWt 6 se0Lats toistelleellsty i.

l G2EGt70 Kre05-0G-3J-F AILS 3EGEDG45-2J 3EGEDG4A-3J 3EGEDG-Tee-3J e.euwe s.Au en i.am-ear a s.=c-ene L

3 I I I 4

Faults Common WEARER 35R WEAIER SER SATTERY P-It! FAILS l .

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ANAL YTf: MIT l CEaT3lm DATE: 06-22-97 -

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Falle Closed fAILLeE F SI 53DL ] l g8 L6ast testen LS-le estLee-o sesas 519eAL FUserfELAf3 us3ee ase k&a7t Lees Of Fwittlen Lielt tuttch LS-9 Felle Clases FIWM IELATE sa30A ase sta7A ssissov 4C-sesas estssoAa ss Las-LF-seasAs ! 1.3K eas ssisev4C-ses3A estsassa sw t.em-est grsee 3.0E ete I.eE set SIsse g_ ,

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FAILifE F FLas TesuhetTRa!N S A

1 E Ritst l FFm 70 ' le 94 v i I I FAlupE TO KT FLeu FalufE TO ET FLau F1unt LME1 Teatu e Flust Last 1malN A ? , I Tecumme eEAIER ER19tl E RIS3S I I I I I fELIEF VALVE Eaftf PIA 8' FALAf3 tu RETIlpi FalATS FAILifE F MSP S FAILifE F L861-8 } LIFT AaC FLOW LISI TRAIN g AFFECT 3s4 Th&IN 8 ale TO IseMICIENT SLET3dpf past . D!vtEION NfW FLSW CpffAlastaff mass i 3 eLRisso eLASSIP GLRiddl SLAIE3d E RISSI 7Ef ' d h

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EMD5 483flCEPRESS iS!5v--sC-1845C ER3930 183tIDW-89-10SdB ER 13 e.est eese 1.ver-ess 8.ast-eas saide Tuss past 4 - Past a 1 FatufE F sang FalusE F seeBC i TO CLON 1 TO CLOK ) 4 GLR 1951 ER1954 TFh TO /\ TFA TO /\ SH 7N , i I I 1 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 Felle Open l

400 V IEC $Mi-25 let Auteeststelly I te annually esenes or senuelly esenes '

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• GLRt978 sEP-sEs t: 3 8.RIS74 #EP-SESt: 3 8.85 987 5. abet i

I 1 I Falu8E F El 1-OHOW8852 3-53-80V-1865-L5-9 FAILifE F SI S301L i 3-St-sew 30E3A t-51 eEN-SE34-LSlo SIGNAL FRes AELAYS Falle Closes Lost Df Functten FastIELATS j l O stt308 asc ar647B GS3tP9dd Leelt Seiten LS-g ets3DA AAC R$d7A Falle Clases Lees Of Functlen Llett briten LS-lO ISIMDV4C-10SN ISILeIS-LF-SSS M 9 95112912 SSIfOV4C-SM 3A i IS! Lee-LF-stS3a n, sisse s.seE cor 3. ggt.een s seo 3.e0E-est 8.2EEaeed 4 !s  ! l I i 3 i i  !

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I l o i t i e i 3 i 4 - I s s Low Hs 0 Safety Ancir'culatitri NAPS Unit 1 ' S/95 PSA 4n'

                                                                                                                                                                                               =v afuaLYST: Isf l M4130N haft 06-3D-1988 ' EVISIO4 : 06-01-95 Fet, ire is ersten i

To set L80 hetet At 90 semire eLRasost c3

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                     $*$1-eeDv 1964A                                                                                                                          I Falls Open i4S*t.d trenster                                                  8-51-eIDV-186dB le east Les                                                                             l-ES-1.d Transfer Falie immen                    to Mot Leg 5                                       hertrculation tsInov40-se644                                                                                                                Rectrculotten e-sts t: 4 4.seE-003                    0.gof,0d sStuov4 0-ta6de                    sEp-stSt:4 f.eEE 803                     8.tef =004 3        -

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3-53-tov-segna 400 V scc sul-an 1stauBN TaalN A MD ELECTRIC POWER ~ FAILINE F FL0u l-5140v-tg885 i i l e ,o ,m Falls Closed 8 Can Met te hecoveres de0V 8Cc SJi-Dets feelthaBN Thalet 5 Fetts Clases & ten

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• 8" d888 LOSS F M $N 4960 l 19A-FflEO-500KV-l TBA-FRED-fEst-C j

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__ __ . - . - . . _ - . - . - .. . _ - . - - ~ . . - - - - .- - ..-._.- i l APPENDIX B j Event Trees l 4 ! A: Large Break Loss of Coolant Accident (LOCA) AD2: Large Break Loss of Coolant Accident (LOCA) & Accumulators Fall To  ! l Inject j j Rx: Reactor Vessel Rupture f

S1: Medium Break Loss Of Coolant Accident i l S1D1: Medium Break Loss Of Coolant Accident (LOCA) Without High Head  !

l Safety injection  ! S2: Small Break Loss Of Coolant Accident (LOCA)

S2D1

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

! Injection  ; i } l 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 l

T1EEQ: Station Blackout (Loss Of Off-site Power & Failure of Diesels to Supply l Power) And Pressurizer PORV Fails Open i T1Hv: Loss Of Off-site Power & Loss Of Emergency Switchgear Room Cooling i 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 Feedwater i T2A: Recoverable Loss Of Main Feedwater l 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 Cooling T3: Transients With Main Feedwater T3Hv: 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 Open T5B: Loss Of Emergency Power DC Bus 1-lll

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 Rupture T7D1: Steam Generator Tube Rupture Without High Head Safety injection ~ T8: Loss Of Emergency Switchgear Room Cooling T9A: Loss Of Emergency Power 4160 V Bus 1H T9AHv: Loss Of Emergency Power 4160 V Bus 1H & Loss Of Emergency Switchgear Room Cooling T9AQ: Loss Of Emergency Power 4160 V Bus 1H & Pressurizer PORV Falls Open T9B: Loss Of Emergency Power 4160 V Bus 1H T9BHv: Loss Of Emergency Power 4160 V Bus 1H & Loss Of Emergency Switchgear Room Cooling T980: Loss Of Emergency Power 4160 V Bus 1H & Pressurizer PORV Fails Open 4 TH: Anticipated Transient Without a Scram ( ATWS) When Greater Than 40% Reactor Power THMFW: Anticipated Transient Without a Scram ( ATWS) When Greater Than 40% , Reactor Power & No Main Feedwater 4 TL: Anticipated Transient Without a Scram (ATWS) When Greater Than 40% Reactor Power , Vx: Interfacing System LOCA ' l l i I 1 l l l

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