ML053080050

Proposed Emergency Technical Specification Change One Time Extension of the Completion Time for the Low Head Safety Injection (Lhsi) Train a

ML053080050
Person / Time
Site:	North Anna
Issue date:	11/03/2005
From:	Hartz L Virginia Electric & Power Co (VEPCO)
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
05-759
Download: ML053080050 (33)

Text

VIRGINIA ELECTRIC AND POWER COMPANY RICHMOND, VIRGINIA 23261 November 3,2005 U.S. Nuclear Regulatory Commission Serial No.05-759 Attention: Document Control Desk NL&OS/ETS RO Washington, D.C. 20555 Docket No. 50-338 License No. NPF-4 VIRGINIA ELECTRIC AND POWER COMPANY (DOMINION)

NORTH ANNA POWER STATION UNIT 1 PROPOSED EMERGENCY TECHNICAL SPECIFICATION CHANGE ONE TIME EXTENSION OF THE COMPLETION TIME FOR THE LOW HEAD SAFETY INJECTION (LHSI) TRAIN A Pursuant to 10 CFR 50.90 and 10 CFR 50.91(a)(5), Dominion requests an emergency amendment of the Facility Operating License, in the form of changes to the Technical Specifications to Facility Operating License Number NPF-4 for North Anna Power Station Unit 1. The proposed change will revise Technical Specification (TS) 3.5.2, Emergency Core Cooling System (ECCS) - Operating, by adding a Note to the Completion Time to allow a one-time 7-day Completion Time to repair a weld leak that was discovered on the Low Head Safety Injection pump suction piping from the Refueling Water Storage Tank (RWST). Dominion requests that the proposed change be processed as an emergency change to prevent an unnecessary plant transient and unscheduled shutdown of North Anna Unit 1. North Anna Unit 1 entered Condition A of TS 3.5.2 at 0330 hours0.00382 days <br />0.0917 hours <br />5.456349e-4 weeks <br />1.25565e-4 months <br /> on November 2, 2005 due to identifying a leak in a weld on the suction piping of the A train of Low Head Safety Injection pump. The current Completion Time for this Condition is 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.

The proposed change is based on a risk-informed evaluation performed in accordance with Regulatory Guides (RG) 1.174, An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions On Plant-Specific Changes to the Licensing Basis, and RG 1.177, An Approach for Plant-Specific, Risk-Informed Decisionmaking:

Technical Specifications. A discussion of the proposed Technical Specifications changes is provided in Attachment 1. The marked-up and proposed Technical Specifications pages are provided in Attachments 2 and 3, respectively.

We have evaluated the proposed Technical Specifications change and have determined that it does not involve a significant hazards consideration as defined in 10 CFR 50.92.

The basis for that determination is provided in Attachment 1. We have also determined that operation with the proposed change will not result in any significant increase in the amount of effluents that may be released offsite and no significant increase in individual or cumulative occupational radiation exposure. Therefore, the proposed amendment is eligible for categorical exclusion as set forth in 10 CFR 51.22(~)(9). Pursuant to 10 CFR 51.22(b), no environmental impact statement or environmental assessment is needed in

Serial No.05-759 Docket No. 50-338 Page 2 of 4 connection with the approval of the proposed changes. The basis for that determination is also provided in Attachment 1.

The proposed, one-time change to Technical Specification 3.5.2, which allows a 7-day Completion Time to repair a weld leak on the Low Head Safety Injection pump suction piping, is consistent with both: 1) Dominions July 23, 2004 (Serial No.04-457) emergency amendment request to permit the repair of a weld leak in a 12-inch LHSl pump suction piping and, 2) Dominions December 17, 2004 (Serial No.04-381) request for amendments to Facility Operating License Numbers NPF-4 and NPF-7. The December 17, 2004 amendment was risk-informed and proposed an increase in the Completion Times for the Emergency Core Cooling System-Low Head Safety Injection subsystem, Auxiliary Feedwater, Quench Spray and Chemical Addition Systems from 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to 7 days.

In order to avoid an unnecessary plant shutdown Dominion requests that the proposed Technical Specification change be reviewed and approved by 1700 hours0.0197 days <br />0.472 hours <br />0.00281 weeks <br />6.4685e-4 months <br /> on November 4, 2005. The extended Completion Time will expire upon returning the A train of the Unit 1 LHSl system to operable status or on November 9, 2005 at 0330 hours0.00382 days <br />0.0917 hours <br />5.456349e-4 weeks <br />1.25565e-4 months <br />, which ever occurs first. If you have any further questions or require additional information, please contact Mr. Thomas Shaub at (804) 273-2763.

Very truly yours, Leslie N. Hartz Vice President - Nuclear Engineering Attachments Commitments made in this letter:

The following compensatory measures will be taken to provide additional assurance that public health and safety will not be adversely affected by this request.

There will be no planned maintenance on either Units Emergency Diesel Generat0rs.

There will be no planned maintenance on the Unit 1 B LHSl ECCS train and both Unit 1 trains of the Recirculation Spray/Casing Cooling Systems.

There will be no planned maintenance activities on switchyard/reserve station service transfor mers.

There will be no planned maintenance on the Alternate AC Diesel Generator (AAC DG).

There will be no planned maintenance on the Unit 1 and 2 high head safety injection pumps including the HHSl cross-tie capability.

There will be no planned testing on the Unit 1 ECCS components that could render them inoperable.

Serial No.05-759 Docket No. 50-338 Page 3 of 4 cc: U.S. Nuclear Regulatory Commission Region I I Sam Nunn Atlanta Federal Center 61 Forsyth Street, SW Suite 237185 Atlanta, Georgia 30303 Mr. J. E. Reasor, Jr.

Old Dominion Electric Cooperative Innsbrook Corporate Center 4201 Dominion Blvd.

Suite 300 Glen Allen, Virginia 23060 Commissioner Bureau of Radiological Health 1500 East Main Street Suite 240 Richmond, VA 23218 Mr. J. T. Reece NRC Senior Resident Inspector North Anna Power Station Mr. S. R. Monarque NRC Project Manager U. S. Nuclear Regulatory Commission One White Flint North 11555 Rockville Pike Mail Stop 8-H12 Rockville, MD 20852

Serial No.05-759 Docket No. 50-338 Page 4 of 4

Subject:

Proposed Emergency Technical Specification Change One Time Extension of the Completion Time for the Low Head Safety Injection (LHSI) Train A COMMONWEALTH OF VIRGINIA )

)

COUNTY OF HENRICO )

The foregoing document was acknowledged before me, in and for the County and Commonwealth aforesaid, today by Leslie N. Hartz who is Vice President - Nuclear Engineering of Virginia Electric and Power Company. She has affirmed before me that she is duly authorized to execute and file the foregoing document in behalf of that Company, and that the statements in the document are true to the best of her knowledge and belief.

Acknowledged before me this  ?=

t-d day of Yo&rn/-~~d , 2005.

My Commission Expires: 31. a 0 6 .

Notary Public (SEAL

Serial No.05-759 Docket No. 50-338 Attachment 1 Discussion of Emergency Technical Specification Change Virginia Electric and Power Company (Dominion)

North Anna Power Station Unit 1

Table of Contents

1. Introduction

2. Background

3. Need for Technical Specification Change

4. Description of Proposed Change 4.1 Technical Specification Change 4.2 Basis of Change

4.3 System Description

5. Technical Evaluation 5.1 Risk Assessment 5.2 Defense-In-Depth Assessment 5.3 Safety Margin Assessment 5.4 Dominant Accident Sequences 5.5 Summary

6. Regulatory Safety Analysis 6.1 No Significant Hazards Consideration 6.2 Environmental Assessment

7. Conclusion Enclosure 1 - North Anna PRA Peer Assessment A & B Level F&O Review Summary

Discussion of Change 1.O Introduction Pursuant to 10 CFR 50.90, Virginia Electric and Power Company (Dominion) requests an emergency amendment to Facility Operating License Number NPF-4 in the form of a change to the Technical Specifications (TS) for North Anna Power Station Unit 1. The proposed change will revise Technical Specification 3.5.2, Emergency Core Cooling System (ECCS) - Operating, by adding a note to the Completion Time to allow a one-time 7- day allowed outage time to repair a weld leak that was discovered on the Low Head Safety Injection pump suction piping. This change should be processed as an emergency change to prevent the shutdown of North Anna Unit 1. The proposed change is based on a risk-informed evaluation performed in accordance with Regulatory Guides (RG) 1.174, An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions On Plant-Specific Changes to the Licensing Basis, and RG 1.177, An Approach for Plant-Specific, Risk-Informed Decisionmaking: Technical Specifications.

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

In addition, the proposed one-time change to Technical Specification 3.5.2, which allows a 7-day Completion Time to repair a weld leak that was discovered on the Low Head Safety Injection pump suction piping, is consistent with a December 17, 2004 (Serial No.04-381) request for amendments to Facility Operating License Numbers NPF-4 and NPF-7 in the form of changes to the Technical Specifications for North Anna Units 1 and 2. The December 17, 2004 amendment request proposed an increase in the Completion Times for the Emergency Core Cooling System-Low Head Safety Injection subsystem, Auxiliary Feedwater, Quench Spray and Chemical Addition Systems from 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to 7 days.

2.0 Background On November 2, 2005, at 0330 hours0.00382 days <br />0.0917 hours <br />5.456349e-4 weeks <br />1.25565e-4 months <br />, personnel discovered a boric acid like substance on the Unit 1 A Low Head Safety Injection (LHSI) pump suction piping from the Refueling Water Storage Tank (RWST). This piping is located in the Safeguards Valve Pit. Samples of the substance were analyzed and they were confirmed to be boric acid.

On November 2, 2005, at 0935 hours0.0108 days <br />0.26 hours <br />0.00155 weeks <br />3.557675e-4 months <br />, non-destructive examination of the piping by liquid penetrant testing in the immediate area of the boric acid deposit identified a one-inch surface crack in the pipe weld. The Unit 1 LHSI pump, l-SI-P-lA, was declared inoperable. Technical Specification 3.5.2 requires two ECCS trains be OPERABLE. The Completion Time of Required Action A . l is 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> with one or more ECCS trains inoperable.

Liquid penetrant (PT) examination identified multiple indications on the weld. A visual examination of the weld on the opposite end of the 45-degree elbow showed similar indications. Ultrasonic (UT) examinations of the welds on the pump suction line are being performed and the results will be provided to the NRC separately.

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In order to return the A LHSl train to OPERABLE, repairs must be completed, non-destructive examinations must be performed, and post-maintenance testing must be performed. The location of the piping that requires weld repaidreplacement is in the valve pit. Access to the Safeguards Valve Pit is a confined space entry by ladder and is approximately 40 feet below ground level. Completion of piping repairs, NDE and post-maintenance testing will extend beyond the current 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Completion Time of Technical Specification 3.5.2. Therefore, a one-time 7-day Completion Time to Required Action A.l of Technical Specification 3.5.2 is requested to repair the weld leak on the A Low Head Safety Injection pump suction piping. The extended Completion Time will expire upon returning the Unit 1 LHSl system to OPERABLE or on November 9, 2005 at 0330 hours0.00382 days <br />0.0917 hours <br />5.456349e-4 weeks <br />1.25565e-4 months <br />, whichever occurs first. This one-time emergency change will prevent an unnecessary shutdown of North Anna Unit 1. The 10-inch line requires a Section XI pipe replacement in accordance with the ASME Code. This includes added difficulties in rigging/pipe fit-up and welding time due to the location of the piping in a confined space. Furthermore, this repair will require several radiographic (RT) exposures to achieve a complete examination and then the performance of post maintenance testing.

On July 23, 2004, Dominion submitted a request for an emergency amendment in the form of changes to the Technical Specifications for North Anna Unit 1 due to a weld leak that was discovered on the 12-inch LHSl pump suction piping. The emergency amendment requested that TS 3.5.2, Emergency Core Cooling System (ECCS) -

Operating, be revised by adding a Note to the Completion Time to allow a one-time 7-day Completion Time to repair the weld leak. The NRC subsequently approved the emergency amendment by letter dated July 23,2004.

A root cause evaluation of the weld leak that occurred in 2004 was performed. The root cause was determined to be the result of defective welding. The defective welding resulted in sensitizing the weld and a lack of fusion may have provided a stress riser for stress corrosion cracking to initiate.

The actual defect was not captured since the weld was ground out. Adjacent weld and base metal was analyzed and found to contain a band of sensitized material.

Sensitized stainless steel is susceptible to cracking under adverse environmental conditions and residual stress. Construction records found that the area with the crack had been repaired for a surface crack. The final radiographic test (RT) of the repaired area showed an area of lack of fusion that was not identified by the radiographer. This was a rejectable condition and should have been repaired. If it was close enough to the inside surface of the pipe this lack of fusion may have served as a stress riser that promoted initiation of a crack.

Corrective action from the root cause evaluation included a review of RT film for 29 Safety Injection and Recirculation Spray welds in the Unit 1 Safeguards Valve Pit and 6 in the Unit 2 Safeguards Valve Pit. The sample included 5 RTs interpreted by the radiographer who missed the lack of fusion in the leaking weld. There were no rejectable defects in the sample. The sample was not expanded since this established a sufficient confidence level in the proficiency of the RT inspectors during construction.

Dominions current practice is to have double review the RT film for safety related components (i.e., Class 1, 2, and 3), to reduce the chance of missing defects. In Page 3 of 24

addition, a sample of ten welds on the LHSl piping in the Unit 1 Safeguards Valve Pit were examined with UT prior to the end of the 2004 fall refueling outage. This selection was limited to the other similar welds, same system conditions, same construction and RT crew. The low points of the system were selected since the concentration of contaminants may be higher in these locations.

The current leaking weld location on the 10-inch LHSl pump suction piping was not included in the review of RT film or the ten welds that were examined by UT during the Unit 1 2004 refueling outage as described above. We have subsequently reviewed the radiographs from the leaking weld and the weld on the opposite of the 45-degree elbow and there were no rejectable defects noted.

As a result of the current weld leak, a visual inspection of 100% of the accessible piping welds in the Unit 1 Safeguards Valve Pit was performed on November 3, 2005. No additional weld discrepancies were identified. The cause of the current weld leak, the extent of condition and associated corrective actions will be determined in accordance with the Corrective Action Program.

Based on the information presented above, it is presumed at this point that the current leakage indication will also be limited in scope to the existing weld and relatively unique to the population of welds in question. Two welds, which are being removed from service in tact, the leaking weld and one other, will be subjected to additional UT and failure analysis to determine the extent of attack and its cause. The results of these evaluations along with recent UT results of other welds in the system will form the basis for the decision determining the number of additional welds which will be UT inspected to assess the extent of the condition and to provide reasonable assurance of no new leaks in the future.

The proposed one-time Completion Time change in this license amendment request has been evaluated in accordance with Regulatory Guide (RG) 1.174, An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis, and RG 1.I 77, An Approach for Plant-Specific, Risk-Informed Decisionmaking: Technical Specifications. The approach addresses, as documented in this report, the impact on defense-in-depth and the impact on safety margins, as well as an evaluation of the impact on risk. The risk evaluation considers the three-tiered approach as presented by the NRC in Regulatory Guide 1.177. Tier 1, PRA Capability and Insights, assessed the impact of the proposed Completion Time changes on core damage frequency (CDF), incremental conditional core damage probability (ICCDP), large early release frequency (LERF), and incremental conditional large early release probability (ICLERP). Tier 2, Avoidance of Risk-Significant Plant Configurations, considers potential risk-significant plant operating configurations, and Tier 3, Risk-Informed Plant Configuration Control and Management, assess emerging plant conditions. Use of the extended Completion Time will be minimized. Scheduling and performing maintenance and surveillance testing will be controlled in accordance with 10 CFR 50.65(a)(4), Maintenance Rule. Although not required by the PRA analysis, compensatory measures will be established to improve defense-in-depth during the extended Completion Time duration.

As discussed above, the proposed one-time Completion Time change is based on a risk-informed evaluation performed in accordance with RG 1.174 and RG 1.177. The Page 4 of 24

CDF impact and the LERF impact, as well as the ICCDP and ICLERP associated with the proposed Completion Time change are summarized below. These values meet the acceptance criteria in RG 1.174 and RG 1.177 for the proposed change.

3.0 Need for Technical Specification Change The proposed one-time change to the Completion Time of North Anna Unit 1 Technical Specifications 3.5.2 is needed to avoid the unnecessary shut down of the plant to complete pipe repair activities. The change averts known risks from complex and error likely plant shutdown and startup evolutions. In addition, the proposed change eliminates the need for preparing, reviewing and approving a Notice of Enforcement Discretion (NOED).

4.0 Description of Proposed Change 4.1 The proposed change will revise the Technical Specifications as follows:

TS 3.5.2 - ECCS-Operatinq

1. A Note is being added to the Completion Time of Condition A to allow a one-time 7-day allowed outage time to permit repair of the Unit 1 LHSl piping.

4.2 Basis for the Technical Specification Change The proposed one-time Completion Time change from 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to 7 days to permit repair of the Unit 1 LHSl piping is based on a risk-informed analysis performed in accordance with RG 1.174 and RG 1.177.

4.3 System Description The function of the ECCS is to provide core cooling and negative reactivity to ensure that the reactor core is protected after any of the following accidents Loss of coolant accident (LOCA), coolant leakage greater than the capability of the normal charging system Rupture of a control rod drive mechanism - control rod assembly ejection accident, Loss of secondary coolant accident, including uncontrolled steam release or loss of feedwater, and Steam generator tube rupture (SGTR).

The ECCS consists of two separate subsystems: the high head safety injection (HHSI) subsystem and the LHSl subsystem. Each subsystem consists of two redundant, 100%

capacity trains. The ECCS accumulators and the RWST are also part of the ECCS, but are not considered part of an ECCS flow path as described in Technical Specification 3.5.2.

The ECCS flow paths consists of piping, valves, and pumps such that water from the RWST can be injected into the reactor coolant system (RCS) following an accident.

The major components of each subsystem are the HHSI pumps and the LHSl pumps.

Each of the two subsystems consists of two 100% capacity trains that are Page 5 of 24

interconnected and redundant such that either train is capable of supplying 100% of the flow required to mitigate the consequences of an accident. This interconnecting and redundant subsystem design provides the operators with the ability to utilize components from the opposite trains to achieve the required 100°/oflow to the core.

The HHSl subsystem consists of three charging pumps providing flow to normal charging, cold legs, hot legs, and seal injection. HHSl pump C is a swing pump that can be powered from either safety bus, but needs to be started manually. In addition, there is a unit-to-unit cross-tie between the HHSl systems. For injection, these pumps take flow from the RWST. The LHSl system consists of two 100% capacity trains, with one LHSl pump per train, providing flow to the cold legs or hot legs. For injection, these pumps take flow from the RWST. During cold leg and hot leg recirculation phase, the LHSl pump suction is transferred to the containment sump. The LHSl pumps then supply flow to the HHSl pumps. In addition, for North Anna Unit 1, there is a cross-tie from the Recirculation Spray System that can provide flow to the LHSl system for long term core cooling.

5.0 Technical Analysis 5.1 Risk Assessment A risk-informed evaluation to determine the impact of the proposed change on plant risk was performed in accordance with Regulatory Guides 1.174 and 1.177.

The Tier 1 and Tier 2 results are discussed below. Tier 3 requirements ensure that the risk impact of out-of-service equipment is evaluated prior to performing any maintenance activity and is met by the Maintenance Rule Program as required by 10CFR50.65(a)(4).

The North Anna WinNUPRA NOAA model was used for the calculational results. This model was deemed suitable for use in this risk-informed application since it models the as-built and as-operated plant. The model has undergone a PRA Industry Peer review. A review of the Peer Review Findings and Observations (F&Os) was performed to ensure that none of the F&Os would invalidate the results of this evaluation. Enclosure 1 contains a matrix with the A and B significance level F&Os from the North Anna PRA Peer Review.

5.1.1 Method of Analysis and Results- Tier 1: PRA Capability and Insights The method of analysis and results for the proposed Completion Time change is discussed below.

In Tier 1, the impact of the Completion Time change of core damage frequency (CDF),

incremental conditional core damage probability (ICCDP), large early release frequency (LERF), and incremental conditional large early release probability (ICLERP) is determined.

ICCDP = [(conditional CDF with the subject equipment out of service) - (baseline CDF with nominal expected equipment unavailabilities)] X (duration of single allowed outage time (AOT) under consideration)

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0 ICLERF = {( conditional LERF with the subject equipment out of service) - (baseline LERF with nominal expected equipment unavailabilities)} X (duration of single AOT under consideration)

Plant specific risk analysis is required to evaluate the impact of the Completion Time change on plant risk being considered in this program due to differences in plant designs and operating history at the plants. The integrated risks associated with the proposed one-time Completion Time change are as follows:

I I With Potential Common 1 Without Potential Common I Cause Cause ICCDP 4.14E-7 1.92E-7 ICLERP 2.88E-9 2.68E-9 These results are well below the RG 1.174 limits of 1E-6 for ICCDP and 1E-7 for ICLERP.

They are also below the RG 1.177 single event limits of 5E-7 for ICCDP and 5E-8 for ICLERP.

Results are presented with and without common cause vulnerability present. The latter is more applicable, since visual inspections have shown no leakage on the redundant train piping.

The results of the risk evaluations associated with the proposed Completion Time change meet the acceptance criteria in RG 1.174 and RG 1.177.

5.1.2 Tier 2: Avoidance of Risk-Significant Plant Configurations North Anna Power Station's program for complying with 10 CFR 50.65(a)(4) fully satisfies the guidance in Regulatory Guide 1.177 for Tier 2 Risk-Informed Configuration Risk Management Program (CRMP). The North Anna 10 CFR 50.65(a)(4) program performs full model PRA analyses of all planned maintenance configurations at power in advance using the SCIENTECH Safety Monitor. The PRA model in the SCIENTECH Safety Monitor is a comprehensive, component level, core damage and large early release model.

The North Anna risk-informed CRMP has been previously evaluated by the NRC in its review and approval of the following amendments: 1) 14-day allowed outage time for the emergency diesel generators (Amendment Nos. 214 and 195), 2) RPS/ESFAS analog instrument surveillance interval extension (Amendment Nos. 221 and 202), 3) 14-day allowed outage time for the PORV nitrogen accumulators (Amendment Nos. 214 and 199), and 4) 7-day allowed outage time for the instrument bus inverters (Amendment Nos. 235 and 217). Configurations that approach or exceed the NUMARC 93-01 risk limits (1.OE-6 cumulative increase in core damage probability) are avoided or addressed by compensatory measures per procedure. Historically, North Anna rarely approaches this limit. Emergent configurations are identified and analyzed by the on-shift staff for prompt determination of whether risk management actions are needed.

The configuration analysis and risk management processes are fully proceduralized in compliance with the requirements of 10 CFR 50.65(a)(4).

The components in the LHSl system are explicitly included in the 10 CFR 50.65(a)(4)

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scope and their removal from service is monitored, analyzed, and managed using the Safety Monitor tool. In addition, possible loss of offsite power hazards (grid loading/stability, switchyard or other electrical maintenance, external events such as severe weather) are all included in the Safety Monitor model and are explicitly accounted for in the (a)(4) program. When configuration risk approaches the (a)(4) risk limits, plant procedures direct the implementation of risk management actions in compliance with the regulations. If the configuration is planned, these steps must be taken in advance.

Individually, most fluid system components do not approach the required risk management thresholds of the (a)(4) regulation. While combinations of unavailable equipment and/or evolutions may approach the limits and even require risk management actions, the risks arising from these configurations will be managed in accordance with station procedures.

Dominion concludes that the North Anna risk-informed CRMP provides reasonable assurance that risk-significant plant equipment outage configurations will not occur when any of the components associated with the Technical Specification request are inoperable. The CRMP has provisions for assessing the need for additional actions if additional equipment-out-of-service conditions exist while the plant is in the risk-informed Completion Time. Therefore, Dominion believes that the North Anna CRMP satisfies the intent of Tier 2 to avoid risk-significant plant configurations.

5.1.3. Tier 3: Risk-Informed Plant Configuration Control and Management North Anna Power Station's program for complying 10 CFR 50.65(a)(4) fully satisfies the guidance in Regulatory Guide 1.177 for Tier 3 Risk-Informed Configuration Risk Management. The North Anna 10 CFR 50.65(a)(4) program performs full model PRA analyses of all planned maintenance configurations at power in advance using the SCIENTECH Safety Monitor. The PRA model in the SCIENTECH Safety Monitor is a comprehensive, component level, core damage and large early release model. The North Anna Regulatory Guide 1.177 Tier 3 Risk-Informed Configuration Management Program has been previously evaluated by the by the NRC in its review and approval of the following amendments: 1) 14-day allowed outage time for the emergency diesel generators (Amendment Nos. 214 and 195), 2) RPWESFAS analog instrument surveillance interval extension (Amendment Nos. 221 and 202), 3) 14-day allowed outage time for the PORV nitrogen accumulators (Amendment Nos. 214 and 199), and

4) 7-day allowed outage time for the instrument bus inverters (Amendment Nos. 235 and 217). Configurations that approach or exceed the NUMARC 93-01 risk limits (a 1.OE-6 cumulative increase in core damage probability) are avoided or addressed by compensatory measures per procedure. Historically, North Anna rarely approaches this limit. Emergent configurations are identified and analyzed by the on-shift staff for prompt determination of whether risk management actions are needed. The configuration analysis and risk management processes are fully proceduralized in compliance with the requirements of 10 CFR 50.65(a)(4).

The LHSl system is included in the 10 CFR 50.65(a)(4) scope and removal from service is monitored, analyzed and managed using the Safety Monitor tool. In addition, possible loss of offsite power hazards (grid loading/stability, switchyard or other electrical maintenance, external events such as severe weather) are all included in the Page 8 of 24

Safety Monitor model and are explicitly accounted for in the (a)(4) program. When configuration risk approaches the (a)(4) risk limits, plant procedures direct the implementation of risk management actions in compliance with the regulations. If the configuration is planned, these steps must be taken in advance.

Individually, most fluid system components do not approach the required risk management thresholds of the (a)(4) regulation. While combinations of unavailable equipment and/or evolutions, may approach the limits and even require risk management actions, the risks arising from these configurations will be managed in accordance with station procedures.

5.1.4 External Events The internal events analysis used for the quantification of the risk impact of the proposed Completion Time change includes internal initiating events and internal flooding. Qualitative assessments were performed for the risk impact of the proposed Completion Time change on seismic, fire, floods and other external events evaluated in the Individual Plant Examination of External Events (IPEEE). The external event analyses have not been updated since completion of the IPEEE, and portions of these analyses were deterministic.

The seismic analysis in the IPEEE used the seismic margins method, which is entirely deterministic. The high confidence of low probability of failure (HCLPF) capacity of the plant was determined to be 0.16g, and was dominated by the overturning moment of large tanks.

The internal fire analysis in the IPEEE used the EPRl FIVE methodology with quantification of the unscreened fire areas. The core damage frequency from internal fires reported in the IPEEE was 4E-6 per year, which is a small fraction of the internal events core damage frequency.

The other events, including high winds, floods, transportation and nearby facility accidents analyses used a screening methodology with quantification of potentially significant events. The only aspect of the other events quantified was the nearby facility accidents analysis. The nearby facility accidents analysis resulted in core damage frequency of 4E-8 per year, which a very small fraction of the internal events core damage frequency.

Table 1 provides a summary of the qualitative assessments of the external event analyses for the requested Completion Time change.

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Table 1 External Event Assessment Completion Time Change - Qualitative Assessment External Event Analysis Emergency Core Cooling (ECCS)

Internal Fire ECCS was not associated with any vulnerabilities or unique significance in fire events.

Seismic ECCS is seismically qualified and was not associated with any vulnerabilities or unique significance in seismic events.

High Winds, Floods, ECCS was not associated with any vulnerabilities or Transportation and Nearby unique significance in these events Facility Accidents 5.1.6 Cumulative CDF and LERF Impact The previously approved and proposed risk-informed changes at North Anna with their associated estimated increase in core damage risk are provided below.

North Anna Risk-Informed Change Estimated Estimated increase in CDF increase in LERF per year per year Approved 14 day emergency diesel 1.3E-06 '1.3E-07 generator allowed outage time extension Approved 7 day inverter allowed outage time 8.1 E-08 4.6E-10 extension Approved reactor protection system and 3E-09 3E-10 engineered safety features actuation system analog channel surveillance test internal extensions from monthly to quarterly and allowed outage time extensions Proposed 7 day emergency core cooling 4.1 E-07 2.9E-09 system allowed outage time extension (assuming only one 7 day entry)

Cumulative Total <1.8E-06 <1.4E-07 "LERF was not calculated, but was estimated based on generic 0.1 containment failure probability for large, dry PWRs.

The cumulative estimated increases in risk associated with all the approved and proposed risk-informed changes is less than 1.8E-06 per year for CDF and 1.4E-07 per year for LERF. These increases in risk are considered acceptably small per Regulatory Guide 1.174.

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5.1.7 PRA Model The PRA model utilized for the evaluation of the Completion Time change is applicable to both Units 1 and 2, and the model reflects the as-built, as-operated plant.

Furthermore, a program exists to periodically update the internal events PRA model in accordance with the Industry Peer Review guidance in NEI 00-02. Enclosure 1 provides a summary of the Findings and Observations from the North Anna industry peer reviews and how this application is impacted by those peer review comments.

5.2 Defense-In-Depth Assessment The proposed change to the ECCS Completion Time maintains the system redundancy, independence, and diversity commensurate with the expected challenges to system operation. The opposite train of emergency power and the associated engineered safety equipment remain operable to mitigate the consequences of any previously analyzed accident. Also, for North Anna Unit 1, there is a cross-tie from the Recirculation Spray System that can provide flow to the LHSl system for long term core cooling. In addition to the Technical Specifications, the Work Management Program, and Maintenance Rule (a)(4) Program provide for controls and assessments to preclude the possibility of simultaneous outages of redundant trains and ensure system reliability. The proposed increase in the Completion Time for the ECCS will not alter the assumptions relative to the causes or mitigation of an accident.

The proposed change needs to meet the defense-in-depth principle consisting of a number of elements. These elements and the impact of the proposed change on each follow:

A reasonable balance among prevention of core damage, prevention of containment failure, and consequence mitigation is preserved.

The proposed Completion Time change has only a small calculated impact on CDF and LERF. The change does not degrade core damage prevention and compensate with improved containment integrity nor do these changes degrade containment integrity and compensate with improved core damage prevention. The balance between prevention of core damage and prevention of containment failure is maintained. Consequence mitigation remains unaffected by the proposed changes.

Furthermore, no new accident or transients are introduced with the requested change and the likelihood of most accidents or transients is not impacted.

Over-reliance on programmatic activities to compensate for weaknesses in plant design.

Safety systems will still function in the same manner with the same reliability. AS noted in the December 17, 2004 submittal, the risk assessment did not identify any plant specific configurations that should be avoided during the entry into the 7-day Completion Time (CT) for planned or emerging maintenancehesting activities of the low head safety injection train. The analysis performed to support the one-time, emergency CT extension request in July 2004 was not as rigorous as the analysis performed to support the subsequent permanent change request to the CT.

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Therefore, compensatory measures were included to provide additional assurance that the low head safety injection function would be available, if required during the ongoing low head safety injection maintenance outage, and to reduce overall plant risk. Therefore, to provide additional defense-in-depth and for consistency with the July 2004 one-time emergency CT extension request the following compensatory measures will be taken to provide additional assurance that public health and safety will not adversely affected by this request.

There will be no planned maintenance on either Units Emergency Diesel Generators.

There will be no planned maintenance on the Unit 1 B LHSl ECCS train and both Unit 1 trains of the Recirculation SprayKasing Cooling Systems.

There will be no planned maintenance activities on switchyardheserve station service transformers.

There will be no planned maintenance on the Alternate AC Diesel Generator (AAC DG).

There will be no planned maintenance on the Unit 1 and 2 high head safety injection pumps including the HHSl cross-tie capability.

There will be no planned testing on the Unit 1 ECCS components that could render them inoperable.

System redundancy, independence, and diversity are maintained commensurate with the expected frequency and consequences of challenges to the system.

There is no impact on the redundancy, independence, or diversity of the Unit 1 ECCS or on the ability of the plant to respond to events with diverse systems. The ECCS is a diverse and redundant system and will remain so.

In addition, ECCS piping will be thoroughly vented following maintenance for the A LHSl piping up to and including the HHSl suction piping.

Defenses against potential common cause failures are maintained and the potential for introduction of new common cause failure mechanisms is assessed.

Defenses against common cause failures are maintained. The Completion Time extension requested is not sufficiently long to expect new common cause failure mechanisms to arise. In addition, the operating environment for these components remains the same so, again, new common cause failures modes are not expected.

In addition, backup systems are not impacted by this change and no new common cause links between the primary and backup systems are introduced. The redundant train of the LHSl system has been evaluated for leakage and the results were satisfactory. Therefore, no new potential common cause failure mechanisms have been introduced by the proposed change.

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Independence of barriers is not degraded.

The barriers protecting the public and the independence of these barriers are maintained. Multiple systems will not be taken out of service simultaneously that could lead to degradation of these barriers and an increase in risk to the public. In addition, the extended Completion Time does not provide a mechanism that degrades the independence of the barriers; fuel cladding, reactor coolant system, and containment.

Defenses against human errors are maintained.

No new operator actions related to the one-time Completion Time extension are required to maintain plant safety. No new operating, maintenance, or test procedures have been introduced due to the change. Operating procedures have been modified to reflect the compensatory measures that are being established.

The increase in the Completion Time provides additional time to complete troubleshooting and test and repair activities which will lead to improved operator and maintenance personnel performance resulting in reduced system re-alignment and re-assembly errors.

It is concluded that defense-in-depth was not impacted by the proposed changes.

5.3 Safety Margin Assessment The overall margin of safety is not decreased due to the increased Completion Time for the ECCS since the system design and operation are not altered by the proposed increase in Completion Time.

The safety analysis acceptance criteria stated in the Updated Final Safety Analysis Report (UFSAR) are not impacted by the change. Redundancy and diversity of the ECCS will be maintained. The proposed change will not allow plant operation in a configuration outside the design basis. The ECCS requirements credited in the accident analysis will remain the same. In addition, for North Anna Unit 1, there is a cross-tie from the Recirculation Spray System that can provide flow to the LHSl system for long term core cooling. It was concluded that safety margins were not impacted by the proposed changes.

5.4 Dominant Accident Sequences The dominant accident sequences were reviewed for the case of one train of the LHSI system unavailable. The results are as follows.

With elevated common cause LHSl vulnerability of the redundant operable train (the RG 1.177 corrective maintenance assumption):

The top sequence is a small break LOCA with successful RCS cooldown and depressurization, but with failure of LHSl recirculation. The dominant failures are common cause failures of the LHSl pumps or the associated MOV's or check valves.

This sequence contributes 42.5% the overall CDF (Sequence CDF = 1.37E-51yr).

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The next sequence is a small break LOCA with failure of HHSl and either the SI accumulators or LHSI. Failure of the RWST or its common isolation valve causes failure of both LHSl and HHSI. This sequence contributes 7.9% of the overall CDF (Sequence CDF = 2.50E-6/yr).

The next two sequences include auxiliary building flooding, resulting in failure of the HHSl and component cooling pumps. These failures lead to an unrecoverable seal LOCA. These sequences contribute 5.7% risk each (11.4% total). They are unrelated to the proposed AOT extension.

There are no other sequences contributing more than 5% to the overall CDF.

Without an elevated common cause LHSl vulnerability:

0 The small break sequences contribute -33% of total risk.

Auxiliary building flooding contributes -30% of total risk.

There are no other sequences contributing more than 8% of total risk.

The large break LOCA is not a significant contributor in either case, due to its low initiating event frequency (-4.5E-61yr). The small break LOCA frequency is -7E-3/yr.

5.5 Summary The proposed Completion Time change is based on a risk-informed evaluation performed in accordance with RG 1.174 and RG 1.177. The ICCDP with and without potential common cause vulnerability is 4.14E-7 and 1.92E-7 respectively. The ICLERP with and without potential common cause vulnerability is 2.88E-9 and 2.68E-9, respectively. These results are well below the RG 1.174 limits of 1E-6 for ICCDP and 1E-7 for ICLERP. They are also below the RG 1.177 single event limits of 5E-7 for ICCDP and 5E-8 for ICLERP. The defense-in-depth and safety margin is not impacted by the proposed changes.

6.0 Regulatory Safety Analysis 6.1 No Significant Hazards Consideration The proposed change will provide a one-time revision the Completion Time of Technical Specification 3.5.2 to allow repair of the Unit 1 LHSl pump suction piping. The proposed change is based on a risk-informed evaluation performed in accordance with Regulatory Guides (RG) 1.174, An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions On Plant-Specific Changes to the Licensing Basis, and RG 1.177, An Approach for Plant-Specific, Risk-Informed Decisionmaking: Technical Specifications. Dominion has evaluated whether or not a significant hazards consideration is involved with the proposed changes by focusing on the three standards set forth in 10 CFR 50.92, Issuance of Amendment, as discussed below:

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

Page 14 of 24

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

The ICCDP with and without potential common cause vulnerability is 4.14E-7 and 1.92E-7 respectively. The ICLERP with and without potential common cause vulnerability is 2.88E-9 and 2.68E-9, respectively. These results are well below the RG 1.174 limits of 1E-6 for ICCDP and 1E-7 for ICLERP. They are also below the RG 1.177 single event limits of 5E-7 for ICCDP and 5E-8 for ICLERP.

Therefore, the proposed change does not involve a significant increase in the probability or consequences of an accident previously evaluated.

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

The proposed change does not involve a physical alteration of the plant (no new or different type of equipment will be installed) or a change in the methods governing normal plant operation. Therefore, the proposed changes do not create the possibility of a new or different kind of accident from any accident previously evaluated.

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

The impact on safety margins is discussed in section 5.3 of this license amendment request. The systems design and operation are not affect by the proposed changes. The safety analysis acceptance criteria are not altered by the proposed changes.

Therefore, the proposed change does not involve a significant reduction in the margin of safety.

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

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

(i) The amendment involves no significant hazards consideration.

As described above, the proposed change involves no significant hazards consideration.

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

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

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

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

Based on the above, Dominion concludes that the proposed changes meet the criteria specified in 10 CFR 51 2 2 for a categorical exclusion from the requirements of 10 CFR 51.22 relative to requiring a specific environmental assessment by the Commission.

7.0 Conclusion The proposed change will allow a one-time revision to the Completion Time for Technical Specification 3.5.2 to allow repair of the Unit 1 A LHSl pump suction piping.

The risk-informed evaluation concludes that the increase in annual core damage and large early release frequencies associated with the proposed change are less than 7E-7/yr and less than 4E-8/yr, respectively, which are characterized as very small changes by RG 1.174. The incremental conditional core damage and large and early release probabilities associated with the proposed change are each within the acceptance criteria in RG 1.177. The proposed change will allow repair of the Unit 1 LHSl pump suction piping without having to shut down the plant since activities will take longer than the current Completion Time. In addition, the proposed extended Completion Time would eliminate the administrative burden of requesting a notice of enforcement discretion for performing pipe repair activities.

The Station Nuclear Safety and Operating Committee (SNSOC) has reviewed the proposed change to the Technical Specifications and have concluded that it does not involve a significant hazards consideration and will not endanger the health and safety of the public.

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Enclosure 1 North Anna PRA Peer Assessment A & B Level F&O Review Summarv The following matrix contains the A and B significance level F&Os from the North Anna PRA Peer Assessment Element F/O Level of Description Impact on Application Significance AS - Accident AS- B Containment vulnerability following LOCAs is None: Addressed by recent update.

Sequence Dev 01/ overly conservative (i.e., core damage AS-10 assumed if containment integrity lost)

AS-02 B LOCA event trees do not have a loss of None: Do not concur with peer review emergency switchgear cooling (HVAC) top significance of observation. Concurrent event loss of emergency switchgear room cooling function and LOCA is a very low likelihood event based on the lack of common cause contributors and the fact that loss of emergency switchgear room cooling can not be a hidden standby system failure. Further, due to redundancy in emergency switchgear room cooling and the slow heatup which results following cooling failures, there is adequate time to respond to such failures before loss of emergency systems needed for LOCA mitigation.

4s-06 B Expand dependency matrix to plant Vone: Modeling of dependencies for the jependencies for IEs and systems 3ffected systems in this application are jetailed and well documented.

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Element F/O Level of Description Impact on Application Significance AS-08 I 6 Address items for AiWS model None: ATWS is a small contributor to the overall risk and the recommended changes to the ATWS model would not lead to ATWS becoming a dominant contributor. The observations on the ATWS model pertained primarily to the pressurizer PORVs, which are not included in the systems affected by this application.

AS-09 6 Enhance documentation of accident None: Documentation issue; does not sequence development to better characterize impact modeling of the affected systems

he interface with IE's and EOP's in this application.

AS- 6 Switch to use a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> mission time instead None: Applies only to emergency diesel 12/ i f 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. generator mission time. Emergency DA-15 diesel generators are not included in the systems affected by this application.

DA - Data DA-04 6 lustify using data collection dates of 1/1/97 - None: Use of different data collection Analysis 12/31/1999 periods for reliability and unavailability data has minimal impact on the results.

The plant specific data collection periods are recent enough to ensure the data matches the current plant operation and design.

~~ ~

DA-08 B Provide appropriate documentation of None: This observation is limited to equipment boundary and population documentation issues associated with definition for data and CCF update equipment boundaries. No errors were discovered in the data analysis related to equipment boundaries.

Page 18 of 24

Element F/O Level of Description Impact on Application Significance DA-09 B Complete plant specific data update. None: Addressed by recent update.

DA-12 B Provide additional CCFs for support systems. None: Potentially risk significant CCFs were incorporated in the recent update for all the affected systems in this application.

DA-13 B Re-evaluate CCF screening criteria. None: Potentially risk significant CCFs were incorporated in the recent update for all the affected systems in this application.

DE - DE- B Minimum volume in the aux bldg internal None: Internal flooding results do not Dependency 01/ flooding analysis appears inconsistent. dominate the risk significance of the DE-02 affected systems in this application.

~~~ ~~

DE-03 B Screening out of turbine bldg for flooding None: Internal flooding results do not doesn't make sense. dominate the risk significance of the affected systems in this application.

DE-04 B Unit 2 CH & CC crosstie was not included in None: Internal flooding results do not the flood analysis. dominate the risk significance of the affected svstems in this application.

HR - Human Y R- A Review HEP dependencies and provide None: Addressed by recent update.

Reliability 31 documentation of results. ~

-IR- A Review REC screening values and verify None: Addressed by recent update.

12 appropriateness of leaving them at 0.1.

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Element F/O Level of Description Impact on Application Significance HR- B The HRA approach provides a thorough None: Do not concur with the 03 analysis of time but there is little or no significance of this observation. The evidence of other performance shaping other performance shaping factors are factors. not as important in determining the failure probability. The HRA results have been subject to significant review in past comparisons to NUREG-1150 studv for Surrv.

HR- B No evidence that the current HRA, including None: Do not concur with the 05 non-updated and updated HEPs, has been significance of this observation. HRA reviewed recently by operations and/or has been subject to significant review in training personnel. past comparisons to NUREG-1150 studv for Surry.

HR- B Improve the guidance for HRA. None: Documentation issue. No 36/ technical issues identified which would HR- impact importance of affected systems 11 in this application.

-1R- B Review event trees to identify human actions None: Documentation issue. No 18 ihat need to be modeled. technical issues identified which would impact importance of affected systems in this application.

iR-19 B i 10 systematic review of indications None: Documentation issue. No technical issues identified which would impact importance of affected systems in this application.

1R- B Treatment of operator actions for dual unit None: None of the dual unit support 0 system support is questionable in some actions impacts the affected systems in cases. this application.

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I Element Level of Description Impact on Application IE - Initiating IE-04 Include loss of IA as a specific IE. None: The primary impact of modeling Events loss of IA as a specific IE would be increased importance of the pressurizer and steam generator PORVs, which are not included in systems affected by this

~

appIication.

I E-07 B Either include additional IE's (MSLB, FWLB, None: Addressed by recent update.

RCS PORV, SRV) in the model or provide L2, Cont Perf Analysis F

L2-03 L2-04 I

B rationale for not including.

Update LERF early Cont failure model

~~~~ ~

Update LERF PRA to include EOP & SAMG actions None: Current LERF model is conservative.

None: Current LERF model is conservative.

Provide LERF definition and consistent LERF None: Current LERF model is w i g nment conservative. The significance of the observation is mitigated by the reasonableness of the assignments using NUREG/CR-6595 and the WOG LERF definitions.

L2-06 B \lo LERF documentation None: Documentation issue. Surry documentation was used as surrogate and is applicable to NAPS due to the design similarities.

L2-09 B 411 SGTR sequences should not result in None: Current LERF model is

-ERF conservative.

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Element F/O Level of Description Impact on Application Significance L2-10 B Revise bypass screening criteria None: Affected systems in this application do not impact interfacing svstem LOCA analvsis.

MU, Maint & MU- B Provide enough time & resources to improve None: Addressed during recent update.

Update 01 Independent Review quality MU- B Several AFW components risk significant at None: Major AFW components, 02 other plants are not in final cut set including the pump are in the cutsets and their risk significance is similar to other PWRs. The absence of individual AFW components or backup systems such as fire water from the cutsets does not significantly impact the risk significance of the affected systems in this application.

MU- B Maintenance and update procedures may None: Observation did not identify any 04 not be sufficient or adequate specific areas of the maintenance or update procedures which were inadequate. The observation was based on the large number of other F&Os, which has subsequently been determined to be unrelated to the maintenance and update procedures.

~

QU, 3U- B Key limitations missing from quantification None: Generic data observation Duantification 12 documentation addressed during recent model update.

~

2U- B PORV logic gate errors in FB1 None: Subsequent review of the feed 13 and bleed fault tree indicates that the existing logic is correct. No change is required.

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Element F/O Significance I Description Impact on Application QU-04 A 1 Concern with 3rdhighest cut set None: The numerous observations have either a minimal impact of risk or result in an over-estimation of the risk.

QU- B Evaluate manual recovery of MS PORVs in None: Minor conservatism in the model 07 SGTR due to not modeling recovery.

SY, Systems SY-0 1 B Fails to Run CCF mission time is not applied None: Addressed by recent update.

Analysis correctly SY-02 B AFW pump automatic actuation failure None: Failure to include manual start of w/manual restart not modeled AFW pumps (upon failure of automatic

~~~

actuation) is a conservatism.

~ ~ ~

SY-09 B HHSl pump restart is not modeled following None: Failure of a pump to restart after LOSP a LOSP is a small contributor and does not significantly impact affected system risk significance.

SY-12 B Replacement Steam Generators not None: Impact of steam generator evaluated replacement is insignificant in terms of affected system success criteria since the changes to SG overall size and heat transfer capacity were relatively minor.

The major impacts of SG replacement are on the timing associated with HRA probabilities, which are expected to be minimal.

~- ~

~~

SY-14 B Incorporate flood scenarios into internal None: There are no dependences events model between increases in test and maintenance unavailability for the affected systems in this application and the flooding model.

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Element F/O Level of Description Impact on Application Significance SY-15 B CCF models missing for CH-MOV-111B/D None: This observation was incorrect, and C/E There are CCFs for these MOVs in the FB4 tree.

SY-19 SG PORV capability w/o IA needs additional None: SG PORVs are not part of any of manual recovery past 5 cycles the affected systems in this application.

TH, Thermal TH-04 B MAAP3B not sufficiently detailed to evaluate None: Only impact of using MAAP3B Hydraulic peak clad temperature success criteria core damage criteria is the Analysis quantification of a few HEP analyses.

Systems affected by this application do not use success criteria based on MAAP core damage definition.

TH-09 B Uncertain about SBO evaluation of SG None: Uncertainty in time to possible overfill on TDAFW pump at 10.4 hrs SG overfill and subsequent failure of TDAFW pump is not as important as the peer review indicates. The difference in a few hours is not critical to the results of the PRA or the importance of the affected systems in this application.

I Page 24 of 24

Serial No.05-759 Docket No. 50-338 Attachment 2 Mark-up of Unit 1 Technical Specifications Change North Anna Power Station Unit 1 Virginia Electric and Power Company (Dominion)

ECCS-Operating 3.5.2 3.5 EMERGENCY CORE COOLING SYSTEMS (ECCS) 3.5.2 ECCS-Operating LCO 3.5.2 Two ECCS t r a i n s s h a l l be OPERABLE.

- - - -- - - - - - - - NOTE- -_ - -_ - _ -----

I n MODE 3, both s a f e t y i n j e c t i o n ( S I ) pump f l o w paths may be i s o l a t e d by c l o s i n g t h e i s o l a t i o n valves f o r up t o 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> t o perform pressure i s o l a t i o n valve t e s t i n g p e r SR 3.4.14.1.

APPLICABILITY: MODES 1, 2, and 3.

ACTIONS CONDITION REQUIRED ACTION COMPLETION TIME A. One o r more t r a i n s A.l Restore t r a i n ( s ) t o ------ NOTE------

inoperabl e. OPERABLE status.

entry i n t o Condition A f o r t h e U n i t 1 "A" t r a i n o f t h e Low Head Safety I n j e c t i o n System i s 7 days 172 hours0.00199 days <br />0.0478 hours <br />2.843915e-4 weeks <br />6.5446e-5 months <br /> I

I B. Required A c t i o n and B.l Be i n MODE 3. 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> associated Completion Time n o t met. AND I B.2 Be i n MODE 4. 1 12 hours C. Less than 100% o f t h e C.l E n t e r LCO 3.0.3. Immediately ECCS flow equivalent t o a s i n g l e OPERABLE ECCS t r a i n avai 1abl e.

I I North Anna U n i t s 1 and 2 3.5.2-1 Amendments ?36*3-~-

Serial No.05-759 Docket No. 50-338 Attachment 3 Proposed Unit 1 Technical Specifications Change North Anna Power Station Unit 1 Virginia Electric and Power Company (Dominion)

ECCS-Operati ng 3.5.2 3.5 EMERGENCY CORE COOL I NG SYSTEMS (ECCS) 3.5.2 ECCS-Operat i ng LCO 3.5.2 Two ECCS t r a i n s shal I be OPERABLE.

In MODE 3, both safety injection (SI) pump flow paths may be isolated by closing the isolation valves f o r up t o 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> t o perform pressure isolation valve testing per SR 3.4.14.1.

APPLICABILITY: MODES I , 2, and 3 ACT IONS COND I T I ON REQU I RED ACT ION COMPLETION T I ME A. One o r more t r a i n s A.l Restore train(s) t o _--__-NOTE------

inoperable. OPERABLE status. The Completion Time f o r the November 2, 2005 entry into Condition A for the Unit 1 "A" t r a i n o f the Low Head Safety In j e c t ion System i s 7 days 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> B. Required Action and B.1 Be i n MODE 3 . 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> assoc i ated Comp I e t i on Time not met. AND B.2 Be i n MODE 4 . 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> C. Less than 100% o f the C.l Enter LCO 3 . 0 . 3 . I mmed i a t e Iy ECCS f l o w equivalent to a single OPERABLE ECCS t r a i n avai lable.

North Anna Units 1 and 2 3.5.2-1