ML020230330

Units 1 & 2, Virginia Electric and Power Company Request for Additional Information License Renewal Applications

ML020230330
Person / Time
Site:	Surry, North Anna
Issue date:	01/16/2002
From:	Christian D Virginia Electric & Power Co (VEPCO)
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
01-686, LR/MWH R0
Download: ML020230330 (50)

Text

VIRGINIA ELECTRIC AND POWER COMPANY RICHMOND, VIRGINIA 23261 January 16, 2002 United States Nuclear Regulatory Commission Serial No.:

01-686 Attention: Document Control Desk LR/MWH RO Washington, DC 20555-0001 Docket Nos.:

50-280/281 50-338/339 License Nos.: DPR-32/37 N PF-4/7 Gentlemen:

VIRGINIA ELECTRIC AND POWER COMPANY (DOMINION)

SURRY AND NORTH ANNA POWER STATIONS UNITS 1 AND 2 REQUEST FOR ADDITIONAL INFORMATION LICENSE RENEWAL APPLICATIONS In an October 22, 2001 letter, the NRC requested additional information regarding the license renewal applications (LRAs) for Surry and North Anna Power Stations. The attachment to this letter contains the responses to the Requests for Additional Information (RAIs) associated with Sections B2.0, 4.1, 4.3, and 4.7.4 of the LRA.

Responses to RAIs associated with Section 2.1 are not provided herein, but will be provided by separate correspondence at a later date.

Should you have any questions regarding this submittal, please contact Mr. J. E.

Wroniewicz at (804) 273-2186.

Very truly yours, David A. Christian Senior Vice President - Nuclear Operations and Chief Nuclear Officer Attachment Commitments made in this letter: None

Serial No.: 01-686 SPS/NAPS LR - Response to RAI cc page 1 of 4 cc:

U. S. Nuclear Regulatory Commission Region II Sam Nunn Atlanta Federal Center 61 Forsyth Street, SW Suite 23T85 Atlanta, GA 30303-8931 Mr. M. J. Morgan NRC Senior Resident Inspector North Anna Power Station Mr. R. A. Musser NRC Senior Resident Inspector Surry Power Station Mr. J. E. Reasor, Jr.

Old Dominion Electric Cooperative Innsbrook Corporate Center 4201 Dominion Blvd.

Suite 300 Glen Allen, VA 23060 Ms. Ellie Irons, EIR Program Manager Virginia Dept. of Environmental Quality 629 East Main St., 6th FI Richmond, VA 23219 Mr. David Paylor, Program Coordinator Virginia Dept. of Environmental Quality P.O. Box 10009 Richmond, VA 23240-0009 Mr. Joe Hassell, Environmental Manager Virginia Dept. of Environmental Quality Water Division P.O. Box 10009 Richmond, VA 23240-0009 Mr. Frank Daniel, Regional Director Virginia Dept. of Environmental Quality Tidewater Regional Office 5636 Southern Blvd.

Virginia Beach, VA 23462

Serial No.: 01-686 SPS/NAPS LR - Response to RAI cc page 2 of 4 Mr. Gregory Clayton, Regional Director Virginia Dept. of Environmental Quality Northern Virginia Regional Office 13901 Crown Ct.

Woodbridge, VA 22193 Mr. Frank Fulgham, Program Manager Virginia Dept. of Agriculture & Consumer Services Office of Plant & Pest Services 1100 Bank St.

Richmond, VA 23219 Mr. David Brickley, Agency Director Virginia Dept. of Conservation & Recreation 203 Governor St.

Richmond, VA 23219 Mr. William Woodfin, Director Virginia Dept. of Game & Inland Fisheries 4010 West Broad St.

Richmond, VA 23230 Mr. Robert Hicks, Director Virginia Dept. of Health Office of Environmental Health Services 1500 East Main St., Room 115 Richmond, VA 23219 Ms. Kathleen S. Kilpatrick, Director Virginia Dept. of Historic Resources State Historic Preservation Office 2801 Kensington Ave.

Richmond, VA 23221 Dr. Ethel Eaton, Archeologist Senior Virginia Dept. of Historic Resources State Historic Preservation Office 2801 Kensington Ave.

Richmond, VA 23221

Serial No.: 01-686 SPS/NAPS LR - Response to RAI cc page 3 of 4 Mr. Robert W. Grabb, Assistant Commissioner Virginia Marine Resources Commission 2600 Washington Ave.

Newport News, VA 23607 Dr. John Olney, Associate Professor Virginia Institute of Marine Science School of Marine Science Gloucester Point, VA 23062 Mr. John Simkins Virginia Dept. of Transportation Environmental Division 1401 East Broad St.

Richmond, VA 23219 Mr. Robert Burnley Virginia Economic Development Partnership 901 East Byrd St.

Richmond, VA 23219 Mr. William F. Stephens, Director Virginia State Corporation Commission Division of Energy Regulation 1300 East Main St., 4th Fl., Tyler Bldg.

Richmond, VA 23219 Mr. Michael Cline, State Coordinator Commonwealth of Virginia Department of Emergency Management 10501 Trade Rd.

Richmond, VA 23236-3713 Mr. Terry Lewis, County Administrator P.O. Box 65 Surry, VA 23883 Mr. Lee Lintecum Louisa County Administrator P.O. Box 160 Louisa, VA 23093

Serial No.: 01-686 SPS/NAPS LR - Response to RAI cc page 4 of 4 Mr. Douglas C. Walker Acting Spotsylvania County Administrator P.O. Box 99 Spotsylvania, VA 22553 Ms. Brenda G. Bailey, County Administrator P.O. Box 11 Orange, VA 22960 Chairman Reeva Tilley Virginia Council on Indians P.O. Box 1475 Richmond, VA 23218 Mr. Don Lillywhite, Director Economics Information Services Virginia Employment Commission State Data Center 703 East Main St., Room 213 Richmond, VA 23219 Mr. Alan Zoellner Government Information Department Swem Library College of William and Mary Landrum Dr.

P.O. Box 8794 Williamsburg, VA 23187-8794 Mr. Walter Newsome Government Information Resources Alderman Library University of Virginia 160 McCormick Rd.

P.O. Box 400154 Charlottesville, VA 22904-4154

Serial No.: 01-686 SPS/NAPS LR - Response to RAI COMMONWEALTH OF VIRGINIA COUNTY OF HENRICO

) )

)

The foregoing document was acknowledged before me, in and for the County and Commonwealth aforesaid, today by David A. Christian who is Senior Vice President and Chief Nuclear Officer of Virginia Electric and Power Company.

He has affirmed before me that he 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 his knowledge and belief.

2001.

Acknowledged before me My Commission Expires:

• j Notary Public (SEAL)

Docket Nos. 50-280/281 50-338/339 Serial No.: 01-686 Attachment Page 1 of 44 Attachment License Renewal - Response to RAI Serial No.01-686 Response to Request for Additional Information Dated October 22, 2001 Surry and North Anna Power Stations, Units 1 and 2 License Renewal Applications Sections B2.0, 4.1, 4.3, and 4.7.4 Virginia Electric and Power Company (Dominion)

Docket Nos. 50-280/281 50-338/339 Serial No.: 01-686 Attachment Page 2 of 44 Appendix B - Aging Management Activities RAI B2.0-1:

In the past, applicants have described the aging management programs in term other than the ten elements as defined in the Standard Review Plan (SRP). On the bases of this concern, the staff is asking that the applicant define the elements of their aging management activities for the staff to clearly understand its application throughout Appendix B. The applicant has the option to verify that they used the same definition presented in the SRP in its development of its aging management activities.

In addition, the applicant takes credit for its 10 CFR Part 50, Appendix B program to satisfy three of the ten elements of an aging management program.

The staff generically accepts Appendix B activities in fulfillment of the corrective action, confirmation process, and administrative control attributes for an aging management program. However, the staff needs to verify that an applicant is correctly applying its Appendix B program to these attributes. Therefore, please provide a description of how Appendix B is applied to the corrective action, confirmation process, and administrative control attributes for an aging management program. In addition, the applicant needs to add a summary description of the QAP as it specifically addresses the corrective action, confirmation process, and administrative controls attributes for an aging management programs to its FSAR Supplement.

Dominion Response:

For the ten elements of the Aging Management Activity descriptions, Dominion uses the definitions provided in the NRC Standard Review Plan (SRP).

The Dominion Quality Assurance Program implements the requirements of 10 CFR 50, Appendix B, and is consistent with Section A.2 of the NRC Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants (NUREG-1 800, April, 2001). The requirements of 10 CFR 50, Appendix B are implemented by the Quality Assurance Program as described in Chapter 17 of the Updated Final Safety Analysis Reports for the Surry and North Anna Power Stations. The Quality Assurance Program includes the elements of corrective action, confirmation process, and administrative controls.

License renewal takes credit for these three elements and confirms their applicability to the safety-related and non-safety-related structures, systems, and components that are within the scope of license renewal.

SCOPE The Corrective Action System, which includes the elements of corrective action, confirmation process, and administrative controls, applies to all safety-related and non safety-related structures, systems, and components that are within the scope of license renewal. Corrective actions implement the requirements of 10 CFR 50, Appendix B.

Docket Nos. 50-280/281 50-338/339 Serial No.: 01-686 Attachment Page 3 of 44 PREVENTIVE ACTIONS The Corrective Action System provides a means to correct conditions that are determined to be adverse to quality. No preventive actions are performed.

PARAMETERS MONITORED OR INSPECTED The Corrective Action System does not involve monitoring any particular system, structure or component within the scope of license renewal.

However, if unexpected inspection results occur, the Corrective Action System provides the mechanism to perform necessary evaluations, repairs, or replacements; and to confirm that corrective actions are performed to ensure that intended functions of systems, structures, and components are maintained.

DETECTION OF AGING EFFECTS The Corrective Action System does not detect aging effects; it provides the mechanism for evaluating and resolving unexpected results from other monitoring activities.

MONITORING AND TRENDING The Corrective Action System provides the mechanism for timely evaluation and resolution of unexpected results from inspection and testing activities.

Plant Issue documents, which summarize these unexpected results, are monitored and trended.

Resolution of plant issues ensures that intended functions of systems, structures, and components are maintained.

ACCEPTANCE CRITERIA The Corrective Action System does not include acceptance criteria; it provides the means to resolve unexpected inspection and testing results that do not comply with acceptance criteria defined in other aging management activities.

CORRECTIVE ACTIONS Corrective actions for conditions that are adverse to quality are performed in accordance with the Corrective Action System as part of the Quality Assurance Program. Any resultant maintenance or repair activities are performed in accordance with the Work Control Process. The corrective action process provides reasonable assurance that deficiencies adverse to quality are either promptly corrected or are evaluated to be acceptable.

Where evaluations are performed without repair or replacement, engineering analysis reasonably assures that the component intended function is maintained consistent with the current licensing basis. If the deficiency is assessed to be significantly adverse to quality, the cause of the condition is determined, and an action plan is developed to preclude repetition. The Corrective Action System identifies repetitive discrepancies and initiates additional corrective action to preclude recurrence.

CONFIRMATION PROCESS Confirmation of activities taken in accordance with the Corrective Action System

Docket Nos. 50-280/281 50-338/339 Serial No.: 01-686 Attachment Page 4 of 44 ensures that resolutions are timely and effective.

ADMINISTRATIVE CONTROLS Administrative and implementation procedures are reviewed, approved, and maintained as controlled documents in accordance with the procedure control process and the Quality Assurance Program.

OPERATING EXPERIENCE Implementing procedures for the Corrective Action System provide direction to document unexpected inspection and testing results as Plant Issues.

Plant Issues document aging affects and significant operating events. Resolution of Plant Issues in accordance with 10 CFR 50, Appendix B maintains the intended functions of systems, structures, and components. Findings from the Corrective Action System are used to enhance the Corrective Action System.

SUMMARY

The Corrective Action System includes the requirements of 10 CFR 50, Appendix B as implemented by the Quality Assurance Program that is described in Chapter 17 of the Updated Final Safety Analysis Reports for Surry and North Anna.

The Quality Assurance Program includes the elements of corrective action, confirmation process, and administrative controls; and is applicable to the safety-related and non-safety related structures, systems, and components that are within the scope of license renewal.

Implementing procedures for the Corrective Action System ensure that unexpected inspection and testing results are documented as Plant Issues and resolved to ensure that intended functions of systems, structures, and components are maintained. The Corrective Action System will remain in place during the period of extended operation.

Docket Nos. 50-280/281 50-338/339 Serial No.: 01-686 Attachment Page 5 of 44 Section 4.1, "Identification of Time-Limited Aging Analyses" RAI 4.1-1:

In both LRAs, Table 4.1-1 the applicant did not identify pipe break postulation based on cumulative usage factor (CUF) as a TLAA.

Section 3A.46 of the NAS updated final safety analysis report (UFSAR) describes the criteria used to provide protection against pipe whip inside the containment. Part of the criteria specifies the postulation of pipe breaks at locations where the CUF exceeds 0.1.

Although the fatigue usage factor calculation was identified as a TLAA, the pipe break criterion was not identified as a TLAA.

However, the usage factor calculation used to identify postulated pipe break locations meets the definition of a TLAA as specified in 10 CFR 54.3 and, therefore, the staff considers the associated criteria for pipe break postulation to be a TLAA. Provide a description of the TLAA performed to address the pipe break criteria for North Anna.

Also identify any pipe break postulations based on CUF at Surry and describe the TLAA performed for these locations. Indicate how these TLAAs meet the requirements of 10 CFR 54.21 (c).

Dominion Response:

To meet the General Design Criteria (GDC-4), intermediate breaks between the terminal points of a Class 1 pipe are postulated when the calculated cumulative usage factor (CUF) is equal to or greater than 0.1. Our review has established that the expected number of transients in 60 years of North Anna Power Station (NAPS) operation will be fewer than the design transients used in the analyses. Consequently, the CUFs will not change for the period of extended operation. Therefore, the CLB pipe break locations remain the same for the period of extended operation.

Only the pressurizer surge lines of Surry Power Station (SPS) have been analyzed to ASME Section III Class 1 rules. Our review establishes that the expected number of transients in 60 years of SPS operation will be fewer than the design transients used in the analyses.

Consequently, the CUFs will not change for the period of extended operation. Therefore, the current SPS CLB pipe break locations remain the same for the period of extended operation.

Docket Nos. 50-280/281 50-338/339 Serial No.: 01-686 Attachment Page 6 of 44 Section 4.3. "Metal Fatique" RAI 4.3-1:

In both LRAs, Section 4.3.1, the applicant discusses its evaluation of the fatigue TLAA for ASME Class 1 components. In this discussion, the applicant indicates that, on the bases of its review of the plant operating history, the number of cycles assumed in the design of the ASME Class 1 components are conservative and bounding for the period of extended operation. Table 5.2-4 of the North Anna UFSAR and Table 4.1-8 of the Surry UFSAR contain a list transient design conditions and associated design cycles.

Provide the following information for each transient listed in these tables:

a. The current number of operating cycles and a description of the method used to determine the number and severity of the design transients from the plant operating history.

b. The number of operating cycles estimated for 60 years of plant operation and a description of the method used to estimate the number of cycles at 60 years.

c. A comparison of the design transients listed in the UFSAR with the transients monitored by the Transient Cyclic Counting Program (TCCP) as shown in Section B3.2 of the LRAs. Identify any transients listed in the UFSAR that are not monitored by the TCCP and explain why it is not necessary to monitor these transients.

d. Section B3.2 of the NAS LRA indicates that the charging line nozzle has been instrumented to evaluate the impact of charging line flow transients. Describe the instrumentation used to monitor charging flow transients explain how the data obtained from this instrumentation is used by the TCCP.

e. In both LRAs, Table 3.1.3-Wi, the applicant provides the response to Renewal Applicant Action Item 11 specified in WCAP -14577, Revision 1-A regarding fatigue TLAA of the reactor vessel internals. The response indicates that the TCCP will assure that the transients will remain within their design values for the period of extended operation. List the transients that contribute to the fatigue usage for each component listed in Table 3-3 of WCAP-14577, Revision 1-A and discuss how the TCCP monitors these transients.

Dominion Response:

a. The transient cycle counting program has been an on-going program at NAPS since the initial startup of each unit, as required by Technical Specifications. The SPS Transient Cycle Counting Program was initiated in January 2000 and operational data since the initial startup of each SPS unit have been included in the cycle counting program.

Tables 4.3-1-1 through 4.3-1-4 list the design transients from the Updated Final Safety Analysis Report (Table 4.1-8 for SPS and Table 5.2-4 for NAPS), the number of design cycles, the number of cycles experienced, and the number of cycles

Docket Nos. 50-280/281 50-338/339 Serial No.: 01-686 Attachment Page 7 of 44 projected for 60 years of operation. The bases for exclusion from the Transient Cycle Counting Program are provided in the footnote. The transient cycle counting data provided in Tables 4.3-1-1 through 4.3-1-4 are compiled through December 31, 1999, for SPS and May 18, 2001, for NAPS. Tables 4.3-1-5 and 4.3-1-6 provide a description of the methods used to determine the number and severity of the design transients monitored for SPS and NAPS, respectively.

The Transient Cycle Counting Program will be continued through the period of extended operation for both plants.

b. Projected cycles for 60 years of SPS and NAPS operation are given in Tables 4.3-1 1 through 4.3-1-4. For NAPS, the number of transient occurrences observed for heatup, cooldown, step load increase of 10% full power, step load decrease of 10%

full power, large step load decrease, loss of flow, and reactor trip from full power are linearly extrapolated to 60 years. This methodology provides a very conservative prediction of future cycles, in that the units typically experience a greater number of transients during the early years of operation.

For SPS, the number of transient occurrences observed for a step load increase of 10% full power, a step load decrease of 10% full power, and a step load reduction from 100% to 50% load are linearly extrapolated to 60 years. For the heatup, cooldown, and reactor trip transients, it was concluded that utilizing the data for all years of operation through December 1999 and linearly extrapolating to 60 years would result in overly conservative projections. This over-projection is due to the significantly large number of startup, shutdown, and reactor trip events that occurred during the first ten years of plant operation. Subsequent to this time period, the frequency of heatups, cooldowns, and reactor trips have been reduced significantly.

In addition, the plant fuel cycle length was changed from 12 months to 18 months during the first ten years of operation, which also contributes to fewer transient events. Therefore, a more realistic approach has been used to extrapolate events out to 60 years. The average frequency on a per-year basis has been derived from more recent operating history (i.e., the last ten years of operation) and has been used as the basis for projecting future cycles.

The average frequency of occurrences on a per year basis for the past 10 years has been doubled for conservatism.

c. Tables 4.3-1-1 through 4.3-1-4 list the design transients from the Updated Final Safety Analysis Report (Table 4.1-8 for Surry and Table 5.2-4 for North Anna), the number of design cycles, the number of cycles experienced, and the projected 60 year cycles. The bases for exclusion from the Transient Cycle Counting Program are provided by footnote.

d. Temperature data from the existing plant instrumentation for the charging lines is being collected so that the operating and design transients for the charging nozzles can be reviewed to validate the design transients.

e. The SPS and NAPS reactor internals were designed to Westinghouse criteria, which were established prior to the issuance of the ASME Code Section III Subsection NG. The Westinghouse criteria contained no TLAAs and used pressure load

Docket Nos. 50-280/281 50-338/339 Serial No.: 01-686 Attachment Page 8 of 44 calculations instead of fatigue calculations.

The Westinghouse design of the reactor vessel internals is similar for both the three loop plants designed with the Westinghouse criteria and the three-loop plants designed with ASME Section III Subsection NG criteria.

In addition, the design transients for the reactor coolant system (RCS), including the reactor vessel internals are similar.

Dominion has evaluated the 40-year reactor coolant system design transients and has concluded that they are applicable to the period of extended operation. The transient cycle counting program will monitor the design transients to provide reasonable assurance that the design cycles are not exceeded.

Docket Nos. 50-280/281 50-338/339 Serial No.: 01-686 Attachment Page 9 of 44 TABLE 4.3-1-1. SURRY UNIT 1 PROJECTED CYCLES AT 60 YEARS OF OPERATION (OCCURRENCES BASED ON DATA FROM INITIAL PLANT STARTUP THROUGH 12/31/99)

UFSAR UFSAIRUNIT 1

RANSIENT TRANSIENT DESCRIPTION TABLE 4.1-8 UNIT 1 PROJECTED NUMBER DESIGN CYCLES POCTED CYCLESCYCLES 1

Heatup at 1OO0 F/hour 200 100 171 2

Cooldown at 1 00°F/hour 200 99 170 3

Loading at 5% of full power per 29,000 Note 1

<29,000 min.(15% to 100% equals one cycle) 4 Unloading at 5% of full power per min.

(100% to 15% equals one cycle) 29,000 Note 1

<29,000 5

Step load increase of 10% full power 2000 6

13 (but not to exceed full power) 6 Step load decrease of 10% full power 2000 7

15 7

Step load reduction from 100% to 200 29 63 50%load 8

Reactor Trip from full power 400 124 208 9

Hydrostatic test pressure, 3107 psi and 5

1 Note 2 10 Hydrostatic test pressure, 2485 psi and 40 Note 3

<40 4000F 11 Steady State Fluctuation Note 4 Notes:

1.

Not counted. Basis for design cycle estimate is load follow operation. Unit does not operate in load follow mode. Instead, the unit is being operated in base-load mode.

2.

Not Counted. One test performed during pre-operational testing. No additional testing is planned for the current or extended license period.

3.

Not counted. ASME Code Case N-498-1 does not require a hydrostatic pressure test above normal operating pressure. No additional testing to be performed.

4.

Not counted. Infinite number of fluctuations assumed.

Docket Nos. 50-280/281 50-338/339 Serial No.: 01-686 Attachment Page 10 of 44 TABLE 4.3-1-2. SURRY UNIT 2 PROJECTED CYCLES AT 60 YEARS OF OPERATION (OCCURRENCES BASED ON DATA FROM INITIAL PLANT STARTUP THROUGH 12131199)

UFSAR UNIT 2 RANSIENT T RANSIENT DESCRIPTION TABLE 4.1-8 UNIT 2 PROJECTED NUMBER DESIGN CYCLES CYCLES CYCLES 1

Heatup at 1OO0 F/hour 200 92 191 2

Cooldown at 1 000F/hour 200 91 190 3

Loading at 5% of full power per min.

29,000 Note 1

<29,000 (15% to 100% equals one cycle) 2900_Nte1_2900 4

Unloading at 5% of full power per 29,000 Note 1

<29,000 min.(100% to 15% equals one cycle)

Step load increase of 10% full power 2000 7

16 (but not to exceed full power) 6 Step load decrease of 10% full power 2000 8

18 7

Step load reduction from 100% to 50%

200 31 69 load 8

Reactor Trip from full power 400 119 232 9

Hydrostatic test pressure, 3107 psi and 5

1 Note 2 1000F 10 Hydrostatic test pressure, 2485 psi and 40 Note 3

<40 4000F 11 Steady State Fluctuation C

Note 4 Notes:

1.

Not counted. Basis for design cycle estimate is load follow operation. Unit does not operate in load follow mode. Instead, the unit is being operated in base-load mode.

2.

Not Counted.

One test performed during pre-operational testing.

No additional testing is planned for the current or extended license period.

3.

Not counted.

ASME Code Case N-498-1 does not require a hydrostatic pressure test above normal operating pressure. No additional testing to be performed.

4.

Not counted. Infinite number of fluctuations assumed.

Docket Nos. 50-280/281 50-338/339 Serial No.: 01-686 Attachment Page 11 of 44 TABLE-4.3-1-3 NORTH ANNA UNIT 1 PROJECTED CYCLES AT 60 YEARS OF OPERATION (OCCURRENCES BASED ON DATA FROM INITIAL PLANT STARTUP THROUGH 5/18/01)

UFSAR UNIT 1 RANSIENT T RANSIENT DESCRIPTION TABLE 5.2-4 UNIT 1 PROJECTED NUMBER DESIGN CYCLES CYCLES CYCLES Normal Transients 1

Heatup at 1 000F/hour 200 40 105 2

Cooldown at 1 000F/hour 200 39 104 3

Loading at 5% of full power per min.

18,300 Note 1

<18,300 (15% to 100% equals one cycle) 4 Unloading at 5% of full power per 18,300 Note 1

<18,300 min.(100% to 15% equals one cycle) 5 Step load increase of 10% full power 2000 3

9 6

Step load decrease of 10% full power 2000 3

9 7

Large step loads decrease 200 2

6 8

Steady State Fluctuation Note 2 Upset Conditions 9

Loss of load, w/o immediate turbine or 80 0

Note 3 Rx trip 10 Loss of power (blackout with natural 40 0

Note 3 circulation in RCS) 11 Loss of Flow (partial loss of flow 1 pump 80 1

3 only) 12 Reactor Trip from full power 400 70 186 13 Inadvertent auxiliary spray 10 0

Note 3 Faulted Conditions 14 Main reactor coolant pipe break 1

Note 5 Note 5 15 Steam pipe break 1

Note 5 Note 5 16 Design-basis earthquake 1

Note 5 Note 5 Test Conditions 17 Turbine roll test 10 Note 4

<10 Hydrostatic Test Conditions 18 Primary side 5

Note 4

<5 19 Secondary side 5

Note 4

<5 20 Primary-side leak test 50 Note 6

<50

Docket Nos. 50-280/281 50-338/339 Serial No.: 01 -686 Attachment Page 12 of 44 TABLE-4.3-1-3 NORTH ANNA UNIT 1 PROJECTED CYCLES AT 60 YEARS OF OPERATION (OCCURRENCES BASED ON DATA FROM INITIAL PLANT STARTUP THROUGH 5/18/01)

(CONT.)

Notes:

1.

Not counted. Basis for design cycle estimate is load follow operation. Unit does not operate in load follow mode. Instead, the unit is being operated in base-load mode.

2.

Not counted. Infinite number of fluctuations assumed.

3.

This transient is tracked. However, it has not occurred in the operational history of the units. No changes to operational philosophy are expected, therefore, this transient is not expected to occur during current license period or period of extended operation. Hence, this transient is projected to not exceed its design cycles limits.

4.

Not counted. Test is an initial startup test only.

5.

Not counted. Faulted condition occurs only once.

6.

Not counted. Leak tests are performed at operating pressure. No system cyclic loading is involved.

Docket Nos. 50-280/281 50-338/339 Serial No.: 01-686 Attachment Page 13 of 44 TABLE-4.3-1-4 NORTH ANNA UNIT 2 PROJECTED CYCLES AT 60 YEARS OF OPERATION (OCCURRENCES BASED ON DATA FROM INITIAL PLANT STARTUP THROUGH 5118/01)

UFSAR TABLE UNIT 2 NSIER TRANSIENT DESCRIPTION 5.2-4 UNIT PROJECTED DESIGN CYCLES CYCLES Normal Transients 1

Heatup at 1 00°F/hour 200 34 98 2

Cooldown at 1 00°F/hour 200 33 97 3

Loading at 5% of full power per min. (15%

18,300 Note 1

<18,300 to 100% equals one cycle) 4 Unloading at 5% of full power per min.

18,300 Note 1

<18,300 (100% to 15% equals one cycle) 5 Step load increase of 10% full power 2000 3

9 6

Step load decrease of 10% full power 2000 3

9 7

Large step loads decrease 200 2

6 8

Steady State Fluctuation Note 2 Upset Conditions 9

Loss of load, w/o immediate turbine or Rx 80 0

Note 3 trip 10 Loss of power (blackout with natural 40 0

Note 3 circulation in RCS) 11 Loss of Flow (partial loss of flow 1 pump 80 1

3 only) 12 Reactor Trip from full power 400 49 140 13 Inadvertent auxiliary spray 10 0

Note 3 Faulted Conditions 14 Main reactor coolant pipe break 1

Note 5 Note 5 15 Steam pipe break 1

Note 5 Note 5 16 Design-basis earthquake 1

Note 5 Note 5 Test Conditions 17 Turbine roll test 10 Note 4

<10 Hydrostatic Test Conditions 18 Primary side 5

Note 4

<5 19 Secondary side 5

Note 4

<5 20 Primary-side leak test 50 Note 6

<50

Docket Nos. 50-280/281 50-338/339 Serial No.: 01 -686 Attachment Page 14 of 44 UFSAR TABLE UNIT 2 NSIER TRANSIENT DESCRIPTION 5.2-4 CYCLES PROJECTED DESIGN CYCLES CYCLES Notes:

1.

Not counted. Basis for design cycle estimate is load follow operation. Unit does not operate in load follow mode. Instead, the unit is being operated in base-load mode.

2.

Not counted. Infinite number of fluctuations assumed.

3.

This transient is tracked. However, it has not occurred in the operational history of the units. No changes to operational philosophy are expected, therefore, this transient is not expected to occur during current license period or period of extended operation. Hence, this transient is projected to not exceed its design cycles limits.

4.

Not counted. Test is an initial startup test only.

5.

Not counted. Faulted condition occurs only once.

6.

Not counted.

Leak tests are performed at operating pressure.

No system cyclic loading is involved.

TABLE 4.3-1-5. SURRY TRANSIENT CYCLE COUNTING - EVENT CRITERIA Heatup RCS temperature increase from Cold Shutdown to above 3500F.

Cooldown RCS temperature decrease from Hot Shutdown to below 3500F.

Step Load Increase A Load -> 5%, turbine online, 5% = -40 MWe.

Step Load Decrease 5% - A Load < 15%, turbine online, 5% = -40 MWe.

Large Load Reduction A Load > 15%, 15% = -120 MWe, no Rx trip.

(Includes Turbine Runbacks)

Reactor Trips Reactor power > 25%

TABLE-4.3-1-4 NORTH ANNA UNIT 2 PROJECTED CYCLES AT 60 YEARS OF OPERATION (OCCURRENCES BASED ON DATA FROM INITIAL PLANT STARTUP THROUGH 5/18/01)

Docket Nos. 50-280/281 50-338/339 Serial No.: 01-686 Attachment Page 15 of 44 TABLE 4.3-1-6. NORTH ANNA TRANSIENT CYCLE COUNTING - EVENT CRITERIA Heatup RCS temperature increase from Cold Shutdown to above 5500F.

Cooldown RCS temperature decrease from Hot Shutdown to below 2000F.

Step Load Increase A Load = 10%, turbine online.

Step Load Decrease A Load = 10%, turbine online.

Large Load Reduction A Load -> 50%, no Rx trip.

(Includes Turbine Runbacks)

Loss of Flow Loss of 1, 2, or 3, RC pumps. Includes loss of AC.

Reactor Trips Reactor power > 25%.

Docket Nos. 50-280/281 50-338/339 Serial No.: 01-686 Attachment Page 16 of 44 RAI 4.3-2:

As discussed in RAI 4.3.1-1, the applicant indicates that the existing design transients and cycle frequencies are conservative and bounding for the period of extended operation.

However, the applicant also indicates that the North Anna reactor pressure vessel closure studs and reactor coolant systems (RCS) loop stop valves were reanalyzed.

Explain why additional analyses were required for these components in light of the statement in the LRAs that design transients and frequencies are conservative and bounding for the period of extended operation.

Dominion Response:

The reactor pressure vessel (RPV) closure studs were originally analyzed for 57 events of tensioning and de-tensioning. Since tensioning and de-tensioning of the RPV head is a subset of heatups and cooldowns, it was decided to re-analyze the RPV closure studs for 200 tensioning and de-tensioning events.

The re-analysis made the tensioning and de-tensioning cycles consistent with the heatup and cooldown cycles.

The reactor coolant system (RCS) loop stop valves were originally analyzed for one event of a steam generator tube rupture. Since there was a tube rupture event at NAPS, the loop stop valves were re-analyzed during the license renewal evaluation to upgrade the values for five (5) steam generator tube rupture events. The re-analysis has shown that the structural integrity of the loop stop valves is maintained with five steam generator tube rupture events.

Docket Nos. 50-280/281 50-338/339 Serial No.: 01-686 Attachment Page 17 of 44 RAI 4.3-3:

For both LRAs, identify whether calculations that meet the definition of a TLAA were performed in response to NRC Bulletin 88-08, "Thermal Stresses in Piping Connected to Reactor Coolant Systems." Describe the actions taken to address this bulletin during the period of extended operation.

Dominion Response:

No fatigue usage calculations that meet the definition of a TLAA were performed to address NRC Bulletin 88-08. No additional actions are intended, beyond the current licensing basis commitments, to addressBulletin 88-08 for the period of extended operation.

Docket Nos. 50-280/281 50-338/339 Serial No.: 01-686 Attachment Page 18 of 44 RAI 4.3-4:

The Westinghouse Owners Group issued Topical Report WCAP-14575-A, "Aging Management Evaluation for Class 1 Piping and Associated Pressure Boundary Components," to address aging management of the RCS piping.

In both LRAs, Section 3.1.1, the applicant addresses the applicability of WCAP-14575-A to North Anna and Surry. Table 3.1.1-Wi of the LRAs contain the response to the renewal applicant action items developed as a result of the staff review of the topical report.

Renewal Applicant Action Item 8 requests that applicants address components labeled I-M and I-RA in Tables 3-2 through 3-16 of WCAP-14575-A. The applicant indicates that the components in Tables 3-2 through 3-16 were addressed by an aging management activity, plant-specific fatigue evaluation, or code evaluation.

However, the applicant did not provide specific details for each component. Provide a summary of the resolution for each of the components labeled I-M and I-RA in Tables 3-2 through 3-16.

Dominion Response:

The components labeled I-M and I-RA in Tables 3-2 through 3-16 are all piping components such as elbows, nozzles, straight pipe etc., which are Class 1 piping and associated pressure boundary components.

These components are analyzed in accordance with the rules of B31.7 for NAPS and the rules of B31.1 for SPS, satisfying the requirements of the appropriate code.

Docket Nos. 50-280/281 50-338/339 Serial No.: 01-686 Attachment Page 19 of 44 RAI 4.3-5:

The Westinghouse Owners Group has issued the generic Topical Report WCAP 14574-A to address aging management of pressurizers. In both LRAs, Section 3.1.4, the applicant discusses the applicability of WCAP-14574-A to North Anna and Surry. In both LRAs, Table 3.1.4-Wi, the applicant provides the response to the renewal applicant action items developed as a result of the staff review of the topical report.

Renewal Applicant Action Item 1 requests that the applicant demonstrate that the pressurizer sub-component CUFs remain below 1.0 for the period of extended operation. Table 2-10 of WCAP-14574-A indicates that the ASME Section III Class 1 fatigue CUF criterion could be exceed at several pressurizer sub-component locations during the period of extended operation.

WCAP-14574-A also identified recent unanticipated transients that were not considered in the original ASME Section III Class 1 fatigue analyses, including inflow/outflow thermal transients.

The response to applicant action item 1 refers to the TLAA evaluation in Section 4.3 of the LRA. The discussion of the pressurizer surge line indicates that the inflow/outflow transients have been evaluated for the pressurizer components. Provide the following information:

a. Confirm that the additional transients discussed in WCAP-14574-A, not considered in the original design, have been addressed at North Anna and Surry.

b. Show the ASME Section III Class 1 CLB CUFs for the applicable sub-components of the North Anna and Surry pressurizers specified in Table 2-10 of WCAP-1 4574-A and the corresponding CUFs for the extended period of operation.

c. Discuss the impact of the environmental fatigue correlations provided in NUREG/CR-6583, "Effects of LWR Coolant Environments on Fatigue Design Curves of Carbon and Low-Alloy Steels," and NUREG/CR-5704, "Effects of LWR Coolant Environments on Fatigue on Fatigue Design Curves of Austenitic Stainless Steels," on the above results.

Dominion Response:

a. Plant-specific NAPS and SPS pressurizer analyses have been performed based on the recommendations made in WCAP-14574-A.

As a result, plant-specific CUF values for all pressurizer locations are available which supersede those documented in WCAP-14574-A. The plant-specific NAPS and SPS analyses include the effects of all additional transients discussed in WCAP-14574-A that were not considered in the original design, including pressurizer insurge/outsurge and stratification effects.

The CUF values calculated in the re-analyses are less than the allowable value of 1.0. These values are given in Table 4.3-5-1.

b. The re-analyses of the NAPS and SPS pressurizers account for the anticipated number of transients up to the end of the period of extended operation. The CUFs are below 1.0 through the period of extended operation.

The ASME Section III Class 1 CLB CUFs for the applicable sub-components of the North Anna and Surry pressurizers, based on the plant-specific analysis discussed

Docket Nos. 50-280/281 50-338/339 Serial No.: 01-686 Attachment Page 20 of 44 under the response to the previous item, are shown in the table below through the period of extended operation. Section 4.3.1 of the LRA provides justification that the existing pressurizer component design cycles and cycle frequencies are conservative and bounding for the period of extended operation. As such, the CLB CUF values for the North Anna and Surry pressurizers provided below in Table 4.3-5-1 are considered to be conservative and bounding through the period of extended operation.

Pressurizer North Anna Surry Subcomponent CLB CUF14)

CLB CUF(4)

Surge Nozzle

+

Corner 0.17 (1) 0.29 (1)

+

Nozzle-to-safe end weld 0.02 (1) 0.30 (1)

+

Safe end-to-pipe weld 0.11(1) 0.05 (1)

Spray Nozzle(6 )

0.848 0.848 Safety and Relief Nozzle(6) 0.148 0.148 Lower Head, Heater Well 0.82 (1) 0.82 (1)

Lower Head to Shell Weld 0.15 (1) 0.14 (1)

Upper Head and Shell 0.849 (2) 0.849 (2)

Support Skirt/Flange 0.0011 0.0011 Manway Pad 0.141 (3) 0.141 (3)

Manway Cover 0.0 0.0 Manway Bolts 0.875 (3) 0.875 (3)

Support Lug 0.048 0.048 Instrument Nozzle 0.13 0.1084 Immersion Heater 0.004 0.004 Valve Support Bracket NA(5)

NA(5)

Notes:

1. CUF value reflects a more recent plant-specific analysis to incorporate the effects of pressurizer insurge/outsurge and stratification transients, as recommended by WCAP-14574-A.

2. Calculated fatigue usage factor is based on a conservative assumption that all spray transients will impinge directly on the pressurizer shell.

3.

Plant-specific CUFs not determined; values from WCAP-14574-A are reported.

4. CUF values are presented for the wetted surface side which may be affected by EAF.

5.

Not applicable since the safety valves are supported by belly bands.

6.

Most limiting location is considered.

TABLE 4.3-5-1 CUF FOR PRESSURIZER SUBCOMPONENTS

Docket Nos. 50-280/281 50-338/339 Serial No.: 01-686 Attachment Page 21 of 44

c. The impact of the environmental fatigue correlations provided in NUREG/CR-6583 and NUREG/CR-5704 are discussed below.

Screening The effects of environmentally assisted fatigue (EAF) are a function of several parameters, including material type, temperature, and dissolved oxygen content.

These effects on individual CUF load pairs can be potentially as high as a factor of fifteen for stainless steel when all relevant conditions are present. However, it is typical for the overall effects of all load pairs for a given component location to be significantly less, since environmental effects do not affect all individual load pairs (due to thresholds beyond which environmental effects are negligible).

Based on the environmental fatigue correlations provided in NUREG/CR-6583, "Effects of LWR Coolant Environments of Fatigue Design Curves of Carbon and Low-Alloy Steels," and NUREG/CR-5704, "Effects of LWR Coolant Environments on Fatigue Design Curves of Austenitic Stainless Steels," bounding Fen multipliers have been determined for the pressurizer to establish a screening value for CUF. These are provided below for each material:

j a ________________________

Low Alloy Steel Fen = exp(0.929 - 0.00124T - 0.101S*T*O*6*)

For a PWR environment, DO < 0.05, so O* = 0.

Therefore, Fen is only dependent upon T.

T (0C)

Fen 0

2.53 50 2.38 100 2.24 150 2.10 200 1.98 250 1.86 300 1.75 Thus, maximum Fen = 2.53 Low Alloy Steel v

Docket Nos. 50-280/281 50-338/339 Serial No.: 01-686 Attachment Page 22 of 44 Carbon Steel Fen = exp(0.585 - 0.00124T - 0.101 S*T*O*e*)

For a PWR environment, DO < 0.05, so 0* = 0.

Therefore, Fen is only dependent upon T.

T (°C)

Fen 0

1.79 50 1.69 100 1.59 150 1.49 200 1.40 250 1.32 300 1.24 Thus, maximum Fen = 1.79 Stainless Steel Fen = exp(O.935 - T*e*O*)

For a PWR environment, DO < 0.05, so 0* = 0.260

• = 0 for T < 2000C or T* = 1 for T > 2000C. Conservatively use T* = 1 Therefore, Fen is only dependent upon the strain rate parameter, e*.

e* = 0 for F > 0.4%/sec so Fen = 2.55 e* = In(e/0.4) for 0.0004 <= F <= 0.4%/sec so Fen = 2.55 to 15.35 e* = In(0.0004/0.4) for, < 0.0004%/sec so Fen = 15.35 Thus, maximum Fen = 15.35

Docket Nos. 50-280/281 50-338/339 Serial No.: 01-686 Attachment Page 23 of 44 Using a bounding Fen multiplier of 2.53 for carbon/low-alloy steel and 15.35 for stainless steel, the revised plant-specific CUF values for all pressurizer subcomponents, including maximum bounding EAF effects, are shown in Tables 4.3-5-2 and 4.3-5-3.

Pressurizer Material Maximum Fen(5)

North Anna SUB-Component EAF CUF Surge Nozzle (Inside Surface)

"+ Corner CS-LAS 2.53 0.430

"+ Nozzle-to-safe end weld SS()

15.35 0.307

"+ Safe end-to-pipe weld SS 15.35 1.689(4)

Spray Nozzle(6)

LAS 2.53 2.145(41 Safety and Relief Nozzle(6)

LAS 2.53 0.374 Lower Head, Heater Well LAS, SS 15.35 12.59(4)

Lower Head-to-Shell Weld LAS 2.53 0.380 Upper Head, Shell LAS 2.53 2.148(4)

Support Skirt/Flange CS 1.00 (2) 0.001 Manway Pad LAS 2.53 0.357 Manway Cover LAS 2.53 0.000 Manway Bolts LAS 1.00 (2) 0.875 Support Lug LAS 1.00 (2) 0.048 Instrument Nozzle SS 15.35 1.996 Immersion Heater SS 15.35 0.0614 Valve Support Bracket Safety valves are supported by a belly band.

Notes:

1.

LAS = low alloy steel, SS = stainless steel. CS = carbon steel

2.

Location is not exposed to the water environment.

3.

Inconel Buttering considered to be stainless steel for environmental effect on fatigue.

4.

Acceptance of these locations is discussed later in Plant-Specific Evaluation.

5.

Conservative Fen value used if more than one material involved.

6.

Most limiting location is considered.

TABLE 4.3-5-2. CUF FOR NAPS BASED ON BOUNDING FEN

Docket Nos. 50-280/281 50-338/339 Serial No.: 01-686 Attachment Page 24 of 44 Pressurizer Material (1)

Maximum Fen(5)

SPS SUB-Component EAF CUF Surge Nozzle (Inside Surface)

+

Corner CS-LAS 2.53 0.734

+

Nozzle-to-safe end weld SS(3) 15.35 4.605(4)

+

Safe end-to-pipe weld SS 15.35 0.768 Spray Nozzle(6)

CS 1.79 1.518(4)

Safety and Relief Nozzle(6)

CS 1.79 0.265 Lower Head, Heater Well CS, SS 15.35 12.59(41 Lower Head-to-shell Weld LAS 2.53 0.354 Upper Head, Shell CS, LAS 2.53 2.148(4)

Support Skirt/Flange CS 1.00 (2) 0.001 Manway Pad CS 1.79 0.253 Manway Cover LAS 2.53 0.000 Manway Bolts LAS 1.00 (2) 0.875 Support Lug LAS 1.0(2) 0.048 Instrument Nozzle SS 15.35 1.662(4)

Immersion Heater SS 15.35 0.0614 Valve Support Bracket Safety valves are supported by a belly band.

Notes:

1.

LAS = low-alloy steel, SS = stainless steel, CS = carbon steel.

2.

Location is not exposed to the water environment.

3.

Inconel Buttering considered to be stainless steel for environmental effect on fatigue.

4.

Acceptance of these locations is discussed later in plant-specific evaluation.

5.

Conservative Fen value used if more than one material is involved.

6.

Most limiting location is considered.

Based on the values shown in the tables above, pressurizer sub-components have acceptable CUF values (i.e., less than the allowable value of 1.0) and are eliminated from further consideration, with the exception of the following:

U U

U U

U Surge Nozzle Spray Nozzle Lower Head, Heater Well Upper Head and Shell Instrument Nozzle Note that the use of the bounding Fen multipliers developed above provide a very conservative basis for assessing the pressurizer with respect to the CUF allowable of 1.0, since actual Fen multipliers are likely to be significantly lower.

TABLE 4.3-5-3. CUF FOR SPS BASED ON BOUNDING FEN

Docket Nos. 50-280/281 50-338/339 Serial No.: 01-686 Attachment Page 25 of 44 The spray nozzle, lower head heater well, upper head and shell, and instrument nozzle are addressed via a plant specific evaluation, as discussed below. The surge nozzle is addressed by aging management, also as discussed below.

Plant-Specific Evaluation Spray Nozzles:

Based on a review of the North Anna and Surry pressurizer analysis, the total spray nozzle CUF of 0.848 is comprised primarily from the fatigue damage of four transient combinations. The four transients are (1) inadvertent auxiliary spray, (2) normal spray above the differential temperature limits allowed by plant procedures during heatup/cooldown, (3) normal spray during heatup/cooldown within differential temperature limits allowed by plant procedures, and (4) normal spray during plant loading and unloading at 5% per minute.

To have thorough mixing in the pressurizer and to prevent an uneven concentration of boron, at Surry and North Anna, the heaters and the pressurizer spray are kept continuously on. Since the pressurizer spray is continuously on, the above transients, which have been considered in the design analysis, are not expected to occur. As a result, the calculated fatigue value becomes almost negligible.

As a result, environmental effects on fatigue on pressurizer spray nozzles are insignificant.

Lower Head and Heater Well:

The heater penetrations in the lower head were not explicitly modeled, but were accounted for in the stress evaluations with appropriate stress intensification factors, which resulted in a very conservative and artificially high value of the CUE.

If detailed finite element calculations are performed for this sub-component, the CUF will be reduced significantly.

No additional actions beyond present aging management activities identified in LRA-Table 3.1.4-1 are planned for the heater wells for the period of extended operation for the following reasons:

"* Inherent margins in the calculation process.

"* The low risk significance associated with these penetrations.

"* Current visual inspections performed on these penetrations as part of the ASME Section XI, Subsections IWB Inservice Inspection Program (as described in LRA Appendix B, Section B2.2.1 1).

" The fact that the surge line weld at the hot leg pipe connection is limiting from a fatigue perspective when considering reactor water environmental effects. Any observed effect of EAF in this surge line weld will result in evaluation of EAF for the pressurizer lower head and heater well location.

Upper Head and Shell:

With respect to the upper head and shell, the original North Anna and Surry

Docket Nos. 50-280/281 50-338/339 Serial No.: 01-686 Attachment Page 26 of 44 pressurizer analyses have conservatively assumed that cold spray flow impinged directly on the upper shell of the pressurizer during the controlling spray transient.

The transient associated with this impingement has contributed to almost all of the CUF for the upper head and shell.

A study conducted by Westinghouse in 1989 established that water droplets from the pressurizer spray nozzle do not impinge on the pressurizer shell at a pressurizer pressure above 320 psig.

In accordance with North Anna and Surry operating procedures, the pressurizer bubble is collapsed and the pressurizer is taken water solid at pressures between 325 and 350 psig. As such, the Westinghouse study is applicable to North Anna and Surry, and direct spray impingement does not occur in the North Anna or Surry pressurizers. Without direct impingement, the associated transient is eliminated, and the reported original CUF of 0.849 for the upper head and shell reduces to a negligible value and, therefore, CUF with EAF will be less than 1.0.

Instrument Nozzle:

No additional actions beyond present aging management activities identified in LRA Table 3.1.4-1 are planned for the instrument nozzle for the period of extended operation for the following reasons:

"* Inherent margins in the calculation process,

"* The low risk significance associated with the nozzle (primarily due to its small size),

" Current visual inspections performed on the instrument nozzle as part of the ASME Section XI, Subsections IWB Inservice Inspection Program (as described in LRA Appendix B, Section B2.2.1 1),

" The fact that the surge line weld at the hot leg pipe connection is limiting from a fatigue perspective when considering reactor water environmental effects. Any observed effect of EAF in this surge line weld will result in evaluation of EAF for the pressurizer instrument nozzle.

As indicated in Section 4.3.4 of the application, Dominion will re-assess environmentally assisted fatigue based on the results of on-going industry activities currently underway by EPRI and the Materials Reliability Program, as well as continued field experience.

Aging Management Surge Nozzle:

As discussed in the response to RAI 4.3-7, pressurizer surge line weld at the hot leg pipe connection will be inspected and used as the leading indicator for EAF concerns.

This inspection commitment is documented in the application as a Licensee Follow-up Action Item in Section B2.2.1 and Table B4.0-1, and will be included in the UFSAR Supplement. The results of these inspections and the results

Docket Nos. 50-280/281 50-338/339 Serial No.: 01-686 Attachment Page 27 of 44 of planned research by the EPRI-sponsored Materials Reliability Program will be utilized to assess the appropriate approach for addressing the issue of environmentally assisted fatigue for applicable components including the surge nozzle.

Thus, EAF has been adequately addressed for all pressurizer subcomponents for the period of extended operation.

Docket Nos. 50-280/281 50-338/339 Serial No.: 01-686 Attachment Page 28 of 44 RAI 4.3-6:

In both LRAs, Section 4.3.4, the applicant discusses the impact of the reactor water environment on the fatigue life of components. The applicant references the fatigue sensitive component locations for an early vintage Westinghouse plant identified in NUREG/CR-6260, "Application of NUREG/CR-5999 Interim Fatigue Curves to Selected Nuclear Power Plant Components."

The LRAs indicates that the results of the NUREG/CR-6260 studies were used to scale up the North Anna and Surry plant specific usage factors for the same locations to account for environmental effects. The LRAs also indicates that the later environmental fatigue correlations contained in NUREG/CR-6583, "Effects of LWR Coolant Environments on Fatigue Design Curves of Carbon and Low-Alloy Steels," and NUREG/CR-5704, "Effects of LWR Coolant Environments on Fatigue on Fatigue Design Curves of Austenitic Stainless Steels,"

were considered in the evaluation. Provide the results of the usage factor evaluation for each of the six component locations listed in NUREG/CR-6260. Discuss how the factors used to scale up the North Anna and Surry plant-specific usage factors were derived.

Also discuss how the later environmental data provided in NUREG/CR-6583 and NUREG/CR-5704 were factored in the evaluations. Discuss the how the North Anna charging line flow transients monitored by the TCCP are factored in these evaluations.

Dominion Response:

Section 4.3.4 of the LRA describes Dominion's evaluation of the impact of the reactor water environment on the fatigue life of the components identified in NUREG/CR-6260, "Application of NUREG/CR-5999 Interim Fatigue Curves to Selected Nuclear Power Plant Components." In particular, that evaluation relies on several industry background studies that have been performed to address EAF effects in RCS components. Those studies have been used to provide an assessment of NAPS and SPS environmental effects on the locations identified in NUREG/CR-6260, using a scaling factor approach.

These locations are identified in Table 4.3-6-1.

TABLE 4.3-6-1. OLDER VINTAGE WESTINGHOUSE PLANT LOCATIONS IDENTIFIED IN NUREG 6260 At core support guide weld Reactor vessel Inlet Nozzle Outlet Nozzle Surge line Hot leg nozzle safe end Charging nozzle Nozzle Safety injection nozzle Nozzle Residual heat removal line Tee

Docket Nos. 50-280/281 50-338/339 Serial No.: 01-686 Attachment Page 29 of 44 Because of the more recent issues raised by the NRC staff relative to the use of the EPRI/GE Fen methodology (Reference EPRI Report No. TR-105759, "An Environmental Factor Approach to Account for Reactor Water Effects in Light Water Reactor Pressure Vessel and Piping Fatigue Evaluations") in various industry applications as well as additional laboratory fatigue data in simulated LWR environments that have been generated by Argonne National Laboratory (ANL) for carbon, low-alloy, and stainless steels, calculations have been revised since the original submittal of the LRA, for the seven locations identified in NUREG/CR-6260 for NAPS and SPS. These calculations are summarized below, and utilize the most recent Fen methodology, as published in NUREG/CR-6583 and NUREG/CR-5704. The conclusions identified in the LRA for NAPS and SPS, which were reached based on the original calculations have been validated by the revised calculations.

RPV Locations The environmental fatigue calculations for the three RPV components identified in NUREG/CR-6260 (RPV shell at core support pads, RPV inlet nozzle, and RPV outlet nozzle) are shown in Table 4.3-6-2. The results show EAF-adjusted CUF values for these three locations of less than 1.0, which are acceptable. The results shown in Table 4.3-6-2 are very conservative, in that the maximum bounding Fen multiplier was conservatively used.

TABLE 4.3-6-2. PLANT-SPECIFIC EAF EVALUATION FOR RPV LOCATIONS AND SURGE LINE Location Original Design Basis CUFs Maximum F,,

Environmental CUFs UNAPS UsPs UNAPS USPS RPV Shell at Core Support Pads 0.092 0.01 2.53 0.233 0.025 RPV Inlet Nozzle 0.022 0.011 2.53 0.056 0.028 RPV Outlet Nozzle 0.074 0.256 2.53 0.187 0.648 Surge Line Hot Leg Nozzle 0.966 0.861 See Note 1 N/A N/A Note: 1. Inspection aging management will be used for this location.

Docket Nos. 50-280/281 50-338/339 Serial No.: 01-686 Attachment Page 30 of 44 TABLE 4.3-6-2. PLANT-SPECIFIC EAF EVALUATION FOR RPV LOCATIONS AND SURGE LINE (CONT.)

Low Alloy Steel Fen = exp(0.929 - 0.00124T - 0.101S*T*O*e*)

For a PWR environment, DO < 0.05, so 0* = 0.

Therefore, Fen is only dependent upon T.

]Thus, maximum Fen = 2.53 Carbon Steel Fen = exp(0.585 - 0.00124T - 0.101S*T*O*s*)

For a PWR environment, DO < 0.05, so 0* = 0.

Therefore, Fen is only dependent upon T.

LThus, maximum Fen = 1.79 Stainless Steel Fen = exp(0.935 - T*e*O*)

For a PWR environment, DO < 0.05, so 0* = 0.260 T* = 0 for T < 2000C or T* = 1 for T > 2000C. Conservatively use T* = 1 Therefore, Fen is only dependent upon the strain rate parameter, 6*.

8* = 0 for, > 0.4%/sec so Fen = 2.55 6* = ln(s/0.4) for 0.0004 <= 8 <= 0.4%/sec so Fen = 2.55 to 15.35 8* = ln(0.0004/0.4) for 8 < 0.0004%/sec so Fen = 15.35 Thus, maximum Fen = 15.35 T (°C)

Fen 0

2.53 50 2.38 100 2.24 150 2.10 200 1.98 250 1.86 300 1.75 T (0C)

Fen 0

1.79 50 1.69 100 1.59 150 1.49 200 1.40 250 1.32 300 1.24

Docket Nos. 50-280/281 50-338/339 Serial No.: 01-686 Attachment Page 31 of 44 Charging Nozzle Location For the charging nozzle, CUF results exist only for NAPS, because the design basis for the SPS piping is USAS B31.1, which does not require explicit fatigue analysis.

However, the detailed plant-specific charging nozzle fatigue calculations for NAPS are not readily retrievable. Therefore, NAPS plant-specific fatigue calculations have been reconstituted based on the inputs used in NUREG/CR-6260. A detailed EAF evaluation for this location was subsequently performed.

The environmental fatigue charging nozzle calculations are shown in Table 4.3-6-3. The results show an EAF adjusted CUF value of less than 1.0, which is acceptable.

Since the SPS design code for the charging piping is USAS B31.1, no explicit fatigue analysis has been performed. However, since the physical attributes of the SPS piping, nozzles, and transient characteristics are similar to those at NAPS, it is concluded that the SPS charging nozzles are likewise acceptable with consideration of EAF.

TABLE 4.3-6-3. PLANT-SPECIFIC EAF EVALUATION FOR CHARGING NOZZLE Step #1: Reproduce NUREGICR-6260 Calculations from Table 5-90 Note 1: Salt = Salt-NB-36o0 since this is the limiting NB-3600 CUF location.

Branch connection/nozzle Salt Naliow n

U Comments body (NB-3600) 363.53 44 20 0.452 46.00 51,814 80 0.002 Note 2 46.00 51,814 120 0.002 Note 2 Total = 0.456 Note 2: Small difference from NUREG/CR-6260; neglected.

Nozzle-to-pipe weld Salt Nallow n

U (NB-3600) 84.62 3,340 20 0.006 70.04 6,951 80 0.012 52.11 27,505 120 0.004 Total = 0.022 Note 3 Note 3: Salt = Salt.NB-3200. Although this is not the limiting NB-3200 CUF location (by only a very small amount), the strain rate is lower than for the nozzle-to-pipe weld location, so this location becomes limiting when environmental effects are considered.

Docket Nos. 50-280/281 50-338/339 Serial No.: 01-686 Attachment Page 32 of 44 TABLE 4.3-6-3. PLANT-SPECIFIC EAF EVALUATION FOR CHARGING NOZZLE (CONT.)

Branch connection/nozzle SO Naliow n

U body (NB-3200) 87.69 2,922 20 0.007 80.94 3,947 80 0.020 29.47 724,304 120 0.000 Total = 0.027 Note 4 Note 4: Limiting NB-3200 location; see note 3 above.

Nozzle region upstream of Sait Naliow n

U Note 5 thermal sleeve Salt Nalow n

UNote 5

(NB-3200) 84.79 3,314 20 0.006 82.86 3,614 80 0.022 46.15 50,897 120 0.002 Total = 0.031

==

Conclusions:==

1. NUREG/CR-6260 calculations are reproduced.

2. Appropriate values of "n" are obtained.

Step #2: Reproduce NAPS CUF by scaling up Sant for Limiting NB-3600 Location Note 5: Salt = Salt.NB-3600-NAPS Multiplier for Salt

= 1.313 Branch connection/nozzle Sait Nallow n

U body:

(NB-3600) 477.31 24 20 0.850 60.40 13,253 80 0.006 60.40 13,253 120 0.009 Total = 0.8647 Note 6 Note 6: The difference is insignificant between this value and NAPS design basis CUF of 0.8646

==

Conclusion:==

1. Above calculation is a reconstituted calculation for NAPS.

Docket Nos. 50-280/281 50-338/339 Serial No.: 01-686 Attachment Page 33 of 44 Safety Injection Nozzle Location For the safety injection nozzle, CUF results exist only for NAPS, because the design basis for the SPS piping is USAS B31.1, which does not require explicit fatigue analysis. However, the detailed plant-specific safety injection nozzle fatigue calculations for NAPS are not readily retrievable. Therefore, plant-specific fatigue calculations have been reconstituted for NAPS based on the inputs used in NUREG/CR-6260. A detailed EAF evaluation was subsequently performed for this location.

The environmental fatigue calculations for the safety injection nozzles are shown in Table 4.3-6-4. The results show an EAF adjusted CUF value of less than 1.0, which is acceptable.

Since the design code for the safety injection piping is USAS B31.1 for SPS, no explicit fatigue analysis has been performed. However, since the physical attributes of the SPS piping, nozzles, and transient characteristics are similar to those at NAPS, it is TABLE 4.3-6-3. PLANT-SPECIFIC EAF EVALUATION FOR CHARGING NOZZLE (CONT.)

Step #3: Create a NAPS NB-3200 CUF from the NB-3600 Calculation Note 7: Salt = Salt-NB-3600-NAPS * (Salt-NB-320/Salt-NB-3600)

Branch connection/nozzle S

Nalyj n

U Note 7 body:

(NB-3200) 115.14 1,118 20 0.018 106.27 1,468 80 0.055 38.69 133,333 120 0.001 Total = 0.0733 Note 8 Note 8: Predicted UNB-3200 for NAPS

==

Conclusion:==

1. Above calculation is reconstituted for NAPS.

Step #4: Determine Fen Multiplier and Environmental CUF Fen for Stainless Steel:

Fen = exp(O.935 - T*F*O*)

For a PWR environment, DO < 0.05, so 0* = 0.260 T* = 0 for T < 2000C or = 1 for T > 2000C. Conservatively use T* = 1 0.08% /sec per strain rate calculation, so e* = ln(e/0.4) for 0.0004 < F < 0.4 %V s.

Calculated Fen = 3.87 Environmental CUF for NAPS = F0n

• UNB-3200 for NAPS = 0.284

Docket Nos. 50-280/281 50-338/339 Serial No.: 01 -686 Attachment Page 34 of 44 concluded that the SPS Safety Injection nozzles are likewise acceptable with consideration of EAF.

TABLE 4.3-6-4. PLANT-SPECIFIC EAF EVALUATION FOR SAFETY INJECTION NOZZLE Step #1: Reproduce NUREG/CR-6260 Calculations from Tables 5-93 and 5-94 FInt

1.

..

Q,.

inr' this i th limitinn NR-3600 CUF location.

air

aII-,'l-dauu Branch Salt Nallow n

U Note 1 connection/nozzle body (NB-3600) 400.22 35 70 1.976 Note 2 Total = 1.976 Note 2:The Salt values for the two other load pairs are unknown; however, the CUF matches so their contribution is nealiaible.

Nozzle-to-pipe weld Salt Nallow N

U (NB-3600) 102.57 1,655 70 0.042 46.79 47,408 50 0.001 Note 3 45.49 55,079 150 0.003 Note 3 Total = 0.046 Note 3: Salt and n values obtained from Table 5-94.

Branch Salt Nalow N

U connection/nozzle body (NB-3200) 32.88 346,189 70 0.000 0.002 Note 4 Total = 0.002 Note 4: The Salt values for the two other load pairs are unknown; this equivalent incremental CUF is chosen so the total CUF results agree.

Nozzle region upstream of Salt Naijow N

U thermal sleeve (NB-3200) 92.48 2,393 70 0.029 0.002 Note 5 Total = 0.031 Note 6 Note 6: Salt = Salt-NB-3200 since this is the limiting NB-3200 CUF location.

Note 5: The Salt values for the two other load pairs are unknown; this equivalent incremental CUF is chosen so the total CUF results agree.

Docket Nos. 50-280/281 50-338/339 Serial No.: 01-686 Attachment Page 35 of 44 TABLE 4.3-6-4. PLANT-SPECIFIC EAF EVALUATION FOR SAFETY INJECTION NOZZLE (CONT.)

Nozzle-to-pipe weld salt Nallow N

U (N1B-3200) 125.14 852 70 0.082 0.013 Note 7 Total = 0.095 Note 7: The Salt values for the two other load pairs are unknown; this equivalent incremental CUF is chosen so the total CUF results agree.

==

Conclusions:==

1. NUREG/CR-6260 calculations are reproduced.

2. Appropriate values of "n" are obtained.

Step #2: Reproduce NAPS CUF by scaling up Salt for Limiting NB-3600 Location multiplier for Salt = 0.669 Note 8: Salt = Salt.NB.3600.NAPS Branch Salt Nallow n

U Note 8 connection/nozzle body:

(NB-3600) 267.75 94 70 0.746 Total = 0.746 Note 9 Note 9: Matches NAPS design basis CUF of 0.746.= UNB.3600 for NAPS

==

Conclusion:==

1. Above calculation is a reconstituted for NAPS.

Step #3: Create a NAPS NB-3200 CUF from the NB-3600 Calculation Note 10: Salt = Salt-NB-3600-NAPS * (Salt-NB-3200/SaIt-NB-3600)

Branch connection/nozzle body:

Salt Naiiow n

U Note 10 (NB-3200) 83.72 3,477 70 0.020 0.013 Note 11 Total = 0.033 Note 12 Note 11: Conservatively use this incremental CUF.

Note 12: Predicted UNB-3200 for NAPS

==

Conclusion:==

1. Above calculation is a reconstituted for NAPS.

Docket Nos. 50-280/281 50-338/339 Serial No.: 01-686 Attachment Page 36 of 44 RHR Tee Location Detailed plant-specific fatigue calculations are available for the NAPS RHR tee.

Therefore, appropriate detailed Fen factors have been calculated for this location to apply to the individual fatigue contributing load pairs and a resulting EAF-adjusted CUF value has been determined.

The environmental fatigue calculations for the RHR tee shown in Table 4.3-6-5 are based on NAPS plant-specific input. The results show an EAF adjusted CUF value of less than 1.0, which is acceptable. Since the design code for the SPS RHR piping is USAS B31.1, no explicit fatigue analysis has been performed. Transient stresses are expected to be similar for NAPS and SPS, since the geometry and material are similar for all four units. Therefore, the results are considered to apply to SPS as well.

TABLE 4.3-6-4. PLANT-SPECIFIC EAF EVALUATION FOR SAFETY INJECTION NOZZLE (CONT.)

Step #4: Determine Fe, Multiplier and Environmental CUF:

Fen for Stainless Steel:

Fen = exp(O.935 - T*s-*O*)

For a PWR environment, DO < 0.05, so 0* = 0.260 T* = 0 for T < 2000C or = 1 for T > 2000C. Conservatively use T* = 1 E = 1.23%/sec per strain rate calculation, so F* = 0 for E > 0.4 %Is.

Calculated Fen = 2.55 Environmental CUF for NAPS = 0.084 = Fen

• UNB-3200 for NAPS

Docket Nos. 50-280/281 50-338/339 Serial No.: 01-686 Attachment Page 37 of 44 TABLE 4.3-6-5. PLANT-SPECIFIC EAF EVALUATION FOR RHR TEE Step #11:

Reproduce design basis fatigue calculation Note 1: NUREG-6260 calculations are not required for this location since a plant-specific calculation exists.

Fen for Stainless Steel:

Fen = exp(0.935 - T*E*O*)

For a PWR environment, DO < 0.05, so 0* = 0.260.

-* = 0 for T < 2000C or = 1 for T > 2000C.

All temperatures for the controlling RHR transient are less than 2000C (3920F),

so T* = 0.

E* does not matter when T* = 0.

Calculated Fen = 2.55 Environmental CUF for NAPS = 0.775 Surge Line/Nozzle Location For the surge line, which is a high CUF location, an aging management program that includes inspection has already been planned to satisfy EAF considerations, as discussed in Sections 4.3.4 and B4.0 of the LRA. Therefore, additional EAF evaluation for this location has not been performed.

Summary of Results for EAF Evaluation The EAF results for all NAPS/SPS locations evaluated above are summarized in Table 4.3-6-6. The results demonstrate that the CUFs for all locations, including postulated environmental effects, remain within the allowable value of 1.0 for 60 years.

Tee salt Nallow n

U (NB-3600) 126.161 657 200 0.304 Total = 0.304

==

Conclusion:==

1. Design basis fatigue calculation is adequately reproduced.

Step #2: Determine Fen Multiplier and Environmental CUF:

Docket Nos. 50-280/281 50-338/339 Serial No.: 01-686 Attachment Page 38 of 44 TABLE 4.3-6-6.SuMMARY OF NAPS/SPS ENVIRONMENTAL FATIGUE CALCULATIONS Environmental No.

Component Maximum Design CUF Multiplier CUF 1

RPV Shell at Core Support Pads 0.092 2.53 0.233 2

RPV Inlet Nozzle 0.022 2.53 0.056 3

RPV Outlet Nozzle 0.256 2.53 0.648 4

Charging Nozzle 0.073 3.87 0.283 5

Safety Injection Nozzle 0.033 2.55 0.084 6

RHR Tee 0.304 2.55 0.775 Charging Line Flow Transients Temperature data (as an indication of flow transients) from the existing plant instrumentation is being collected so that a comparison of operating and design transients for the charging nozzles can be made to validate the design transients.

These data are planned to be used only for validating the design transients. They are not included in the above evaluations.

Docket Nos. 50-280/281 50-338/339 Serial No.: 01-686 Attachment Page 39 of 44 RAI 4.3-7:

In both LRAs, Section 4.3.4, the applicant indicates that the pressurizer surge line required further evaluation for environmental fatigue during the period of extended operation. The applicant further indicates that it would use an aging management program to address fatigue of the surge line during the period of extended operation.

The aging management program would rely on an augmented inspection program to address surge line fatigue during the period of extended operation. As indicated in the draft safety evaluation on Westinghouse Owners Group generic technical report WCAP

-14575, License Renewal Evaluation: Aging Management Evaluation for Class 1 Piping and Associated Pressure Boundary Components," the NRC has not endorsed a procedure on a generic basis which allows for augmented inspections in lieu of meeting the fatigue usage criteria.

The applicant has not provided a technical basis demonstrating the technical adequacy of its proposal.

Provide a detailed technical evaluation which demonstrates the proposed inspections provide an adequate technical basis for detecting fatigue cracking before such cracking leads to through wall cracking or pipe failure. The detailed technical evaluation should be sufficiently conservative to address all uncertainties associated with the technical evaluation (e.g., fatigue crack initiation and detection, fatigue crack size, and fatigue crack growth rate considering environmental factors). As an alternative to the detailed technical evaluation, provide a commitment monitor the fatigue usage, including environmental effects, during the period of extended operation, and to take corrective actions, as approved by the staff, if the usage is projected to exceed one.

Dominion Response:

The proposed aging management program to address environmentally assisted fatigue of the SPS and NAPS pressurizer surge lines during the period of extended operation is to inspect in accordance with the appropriate requirements of ASME Boiler and Pressure Vessel Code,Section XI, Rules for Inservice Inspection of Nuclear Power Plant Components. Inspection frequency will be supported by methods similar to the approach documented in the ASME Boiler and Pressure Vessel Code, Section Xl, Non mandatory Appendix L. However, Dominion recognizes that to date, the NRC has not endorsed the Appendix L approach.

The primary NRC concerns with Appendix L include crack aspect ratio and acceptable fatigue crack growth rates (including environmental effects).

Some of the pressurizer surge line welds at SPS and NAPS have been ultrasonically examined in the past. No reportable indications have been found. Section 4.3.4 of the application states that the surge line weld at the hot leg pipe connection will be included in an augmented inspection program, so that flaw initiation and growth can be detected and/or monitored. Baseline inspections of these welds are planned prior to entry into the period of extended operation, and they will also be inspected once per period. The results of these inspections and the results of planned research by the EPRI-sponsored Materials Reliability Program will be utilized to assess the appropriate approach for addressing environmentally assisted fatigue of the surge lines.

The approach developed could include one or more of the following:

Docket Nos. 50-280/281 50-338/339 Serial No.: 01-686 Attachment Page 40 of 44

1.

Further refinement of the fatigue analysis to lower the CUF(s) to below 1.0, or

2.

Repair of the affected locations, or

3.

Replacement of the affected locations, or

4.

Manage the effects of fatigue by an inspection program that has been reviewed and approved by the NRC (e.g., periodic non-destructive examination of the affected locations at inspection intervals to be determined by a method accepted by the NRC).

Should Dominion select Option 4 (i.e., inspection) to manage environmentally assisted fatigue during the period of extended operation, inspection details such as scope, qualification, method, and frequency will be provided to the NRC for review prior to entering the period of extended operation. This position is consistent with previous applicants' positions. Licensee Follow-up Action for surge line inspection has been identified in LRA Table B4.0-1 and will be included in the UFSAR Supplement.

Docket Nos. 50-280/281 50-338/339 Serial No.: 01-686 Attachment Page 41 of 44 Section 4.7.4. "Spent Fuel Pool Liner" RAI 4.7.4-1:

Please provide a tabulated summary of the number of'cycles considered in the fatigue analysis for normal, upset, emergency, and faulted conditions together with the temperature ranges considered for each condition.

Dominion Response:

CONDITIONS DESCRIPTION DESIGN CYCLES TEMPERATURE RANGE Condition 1 1/3 Core Initial Load 1

70OF - 121 OF (Normal)

Condition 2 1/3 Core Refuel with 10 years 80 70°F - 135 0F (Normal) fuel in the pool Condition 3 1 core off load - 45 days after 8

70OF -

170OF Upset refueling abnormal condition Condition 4 Faulted condition 1

70°F -212°F Faulted The above cycles envelop the operating applicable to both SPS and NAPS.

cycles for 60 years. These cycles are

Docket Nos. 50-280/281 50-338/339 Serial No.: 01-686 Attachment Page 42 of 44 RAI 4.7.4-2:

What is the temperature range considered in calculating the allowable thermal cycles for the most severe thermal cycles?

Dominion Response:

The NAPS and SPS analyses consider the range of 70°F - 212°F for the most severe thermal cycles.

Docket Nos. 50-280/281 50-338/339 Serial No.: 01 -686 Attachment Page 43 of 44 RAI 4.7.4-3:

As the stainless pool liner is attached to the concrete walls and the bottom slab (or basemat), the fatigue characteristics of the liner will be influenced by the integrity of its anchorages to the concrete, and the effects of high sustained (> 15 days) temperature on the concrete. Please provide a summary of procedures used to incorporate these effects in the pool liner time-limited fatigue analysis.

Dominion Response:

The NAPS pool liner was designed in accordance with the design criteria provided in the ASME Boiler and Pressure Vessel Code,Section III, Division 1 -

1974 edition; Nuclear Power Plant Components, Subsection NA (with addenda up to Summer 1976).

The SPS pool liner was designed in accordance with the design criteria provided in the ASME Boiler and Pressure Vessel Code,Section III, Division 1 - 1971 edition. The following procedure was used in the existing calculations to qualify the fuel pool liner.

Procedure:

1.

Membrane plus bending stresses caused by differential thermal expansion was calculated using linear elastic methods of analysis.

2.

If one of the following two conditions were met, the liner was considered to be acceptable.

"* If stresses calculated at points, which are not welds or points of stress concentrations, the calculated stresses should be less than 3Sm.

If stresses calculated at points, which are welds or points of stress concentrations, the calculated stresses should be less than 0.7 5Sm. (Note:

The limit of 0.75 Sm results in a stress concentration factor of 4.0.)

3.

If the calculated stresses exceed either 3S. or 0.75Sm as identified in 2, then the liner is evaluated on the basis of fatigue life. The liner integrity was assessed in accordance with the cyclic loading design procedure, Paragraph XIV-1221.3, Pages 336 and 337 of Section II1. Stresses to determine the fatigue life was calculated as follows:

"* Stress concentration factor of 1.0 was used for points, which are not welds or points of stress concentrations.

"* Stress concentration factor of 4.0 was used for points, which are welds or points of stress concentrations.

4.

Appropriate design stress intensity values from Section III were used.

5.

The applicable design fatigue curve from Section III was used.

For the locations with welds or stress concentrations, a factor of 4 has been used. The most limiting condition is that the concrete structure is deformed to its maximum

Docket Nos. 50-280/281 50-338/339 Serial No.: 01-686 Attachment Page 44 of 44 permissible limit and is at room temperature. The liner design calculations show that the allowable cycles for the liner reaching 212°F are 100 for North Anna and 95 for Surry.

This number of allowable cycles exceeds the total number of expected operating cycles (90) as identified in Section 4.7.4 of the application. Furthermore, the temperature of the fuel pool is expected to be below 135°F under normal conditions. Since the operating temperature is low, effects of sustained high temperature is not a concern.

The welding at the Surry anchorages has been analyzed for fatigue usage factor using the operating cycles listed above. It was found to be 0.578, which is less than the allowable value of 1.0. No additional analysis has been performed for North Anna, since the SPS liner is the most limiting.