ML022130481

Stations, Units 1 & 2, License Renewal - Draft SER Response to Open Items & Confirmatory Actions

ML022130481
Person / Time
Site:	Surry, North Anna
Issue date:	07/25/2002
From:	Hartz L Virginia Electric & Power Co (VEPCO)
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
02-360, LR/DWL R0
Download: ML022130481 (94)

Text

VIRGINIA ELECTRIC AND POWER COMPANY RICHMOND, VIRGINIA 23261 July 25, 2002 United States Nuclear Regulatory Commission Serial No.:

02-360 Attention: Document Control Desk LR/DWL RO Washington, DC 20555-0001 Docket Nos.:

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

VIRGINIA ELECTRIC AND POWER COMPANY (DOMINION)

SURRY AND NORTH ANNA POWER STATIONS UNITS I AND 2 LICENSE RENEWAL - DRAFT SER RESPONSE TO OPEN ITEMS AND CONFIRMATORY ACTIONS Dominion received the draft Safety Evaluation Report (SER) for the Surry and North Anna License Renewal by letter dated June 6, 2002. The draft SER identifies eight (8) open items and fifteen (15) confirmatory actions for Surry and North Anna Power Stations. Attachment 1 to this letter provides a response to each of the open items. For some open items, the response references correspondence that has been previously submitted addressing the open item issue. Attachment 2 to this letter provides a disposition for each of the confirmatory actions identified in the draft SER.

Both Surry and North Anna were required by 10 CFR 54.21(d) to include a proposed supplement to the UFSAR in their License Renewal Application (LRA). This was provided as Appendix A in both LRAs.

As a result of discussions with the staff and commitments made as part of the review process, Dominion has revised the proposed UFSAR supplements for both stations. Attachment 3 to this letter provides the revised UFSAR supplement for Surry. Attachment 4 provides the revised UFSAR supplement for North Anna.

Each proposed UFSAR supplement has been reformatted from the original LRA Appendix A to a "Chapter 18" format in anticipation of incorporation into the UFSAR as the description of aging management programs. Information provided in the proposed UFSAR supplements is referenced in the disposition of open items and confirmatory actions provided in Attachments 1 and 2.

Serial No.02-360 Page 2 of 2 to this letter provides the Dominion position regarding the subject of electrical fuse holders. Although this subject was not addressed as a concern in the draft SER, it has been identified as an emerging issue for license renewal. Dominion is, therefore, providing this information for your consideration.

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

Wroniewicz at (804) 273-2186.

Very truly yours, Leslie N. Hartz Vice President - Nuclear Engineering Attachments (5)

Commitments made in this letter: None

Serial No.: 02-360 SPS/NAPS LR - Response to Draft SER 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., 6 th 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.: 02-360 SPS/NAPS LR - Response to Draft SER 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.: 02-360 SPS/NAPS LR - Response to Draft SER 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., 4t 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.: 02-360 SPS/NAPS LR - Response to Draft SER 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

SN: 02-360 Docket Nos.: 50-280/281 50-338/339

Subject:

LR - Response to Draft SER 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 25th day of July, 2002.

My Commission Expires: March 31, 2004.

otary Public (SEAL)

Docket Nos. 50-280/281 50-338/339 Serial No.: 02-360 Page 1 of 8 License Renewal - Response to Draft SER Open Items Serial No.02-360 Surry and North Anna Power Stations, Units I and 2 License Renewal Virginia Electric and Power Company (Dominion)

Page 1

Docket Nos. 50-280/281 50-338/339 Serial No.: 02-360 Page 2 of 8 Response to Draft SER Open Items Surry and North Anna Power Stations Open Item 2.5-1. Consistent with the requirements specified in 10 CFR 54.4(a)(3) and 10 CFR 50.63(a)(1), the plant system portion of the offsite power system should be included within the scope of license renewal. In the North Anna and Surry LRAs, the applicant did not include the offsite power systems into the scope of license renewal.

The applicant stated that the North Anna and Surry station blackout analysis relied primarily on the recovery of the emergency diesel generators. The staff disagreed with the applicant as it would affect scoping for license renewal rule under 10 CFR 54.4(a)(3). The 10 CFR 50.63(a) states that the station blackout duration shall be based on "the expected frequency of loss of offsite power" and "the probable time needed to restore offsite power." Based on this information, the staff required that applicable offsite power structures and components be included within the scope of license renewal and subject to an aging management review, or additional justification for its exclusion be provided.

Dominion Response:

The plant portion of the offsite power system for Surry and North Anna has been included in the license renewal scope for a station blackout event as per 10 CFR 54.4(a)(3). Separate correspondence (Serial No.02-297 dated July 11, 2002) on this subject provides a revised response to RAI 2.5-1 which details the added scope equipment and summarizes the aging management reviews for components and/or materials not previously addressed by the original LRAs.

==

Conclusion:==

Based on this response and the information provided in the above referenced letter, Dominion requests that Open Item 2.5-1 be closed.

Open Item 3.9.2-1. The applicant provided an aging management activity for non-EQ cables and connectors within the scope of license renewal in a letter dated November 30, 2001. The staff found that the submitted aging management activity is essentially a visual inspection program that addresses age-related degradation of cable jackets and connector coverings that can result from exposure to high values of temperature or radiation, or to wetted conditions. This visual inspection program covers areas that are addressed under three separate programs within the GALL report.

The aging Page 2

Docket Nos. 50-280/281 50-338/339 Serial No.: 02-360 Page 3 of 8 management activity submitted by the applicant does not utilize the calibration approach for non-EQ electrical cables used in circuits with sensitive, and low level signals.

Because a moist environment can apparently hasten the failure of these circuits if they have previously undergone age-related degradation, the disposition of a degraded cable should consider the potential for moisture in the area of the degradation. The applicant should verify that this is the case for the corrective-actions attribute of the North Anna and Surry Non-EQ Cable monitoring activity.

Dominion Response:

By letter dated November 30, 2001 (Serial No.01-647) Dominion provided an evaluation of the North Anna and Surry Non-EQ Cable Monitoring Aging Management Activities, in terms of the aging management program attributes provided in the Standard Review Plan for license renewal. The discussion of the Corrective Actions attribute provided a description of the engineering evaluation and corrective action processes which provide reasonable assurance that the component's intended function is maintained consistent with the current licensing basis. This description of the engineering evaluation process has been enhanced in the revised Non-EQ Cable Monitoring AMA to ensure that if a degraded cable is identified, the cable environment including the potential for moisture in the area of degradation shall be considered in the engineering evaluation and appropriate corrective actions initiated through the Corrective Action System. Separate correspondence (Serial No.02-297 dated July 11, 2002) on this subject provided a supplemental response to RAI 3.6.2-1 which incorporated the changes discussed above. Section 18.1.4 of the proposed UFSAR supplement has also been revised to include the consideration of cable environment in the evaluation of degraded cable.

==

Conclusion:==

Based on the information provided above and the proposed UFSAR supplements attached to this letter, Dominion requests that Open Item 3.9.2-1 be closed.

Open Item 3.9.2-2. The applicant should provide a technical justification for high voltage neutron monitoring instrumentation cables and radiation monitor cables that will demonstrate that visual inspections will be effective in detecting damage before current leakage can affect instrument loop accuracy.

The high voltage portion of the neutron monitoring system would appear to be a worst case subset of the low signal level instrumentation circuit category. These circuits operate with low level logarithmic signals so are sensitive to relatively small changes in signal strength, and they operate at a high voltage which could create larger leakage Page 3

Docket Nos. 50-280/281 50-338/339 Serial No.: 02-360 Page 4 of 8 currents if that voltage is impressed across associated cables and connectors.

Radiation monitoring cables have also been found to be particularly sensitive to thermal effects. NRC Information Notice 97-45, Supplement 1 describes this phenomenon. The neutron monitoring circuits and radiation monitors, therefore, might be candidates for the calibration approach but not necessarily the visual inspection approach.

Dominion Response:

Dominion has reviewed the neutron monitoring instrumentation cables and radiation monitoring cables installed at Surry and North Anna Power Stations which operate between 1 kV and 5kV and transmit signals supporting a license renewal intended function. Results of this review have determined that the source, intermediate, and power range neutron detector cables are the only cables meeting the above criteria that are not included in the environmental qualification program. (i.e. non-EQ cable)

The source, intermediate, and power range neutron detector cables are frequently energized in the "high" voltage range, (i.e., 1 kV and 5kV), and a reduction in insulation resistance (IR) could be a concern for these cables since reduced IR may contribute to inaccuracies in the instrument loop. The routine calibration tests performed as part of the plant surveillance test program will be used to identify the potential existence of this aging degradation. Separate correspondence (Serial No.02-297 dated July 11, 2002) on this subject provided a supplemental response to RAI 3.6.2-1 which credits the normal calibration frequency specified in the plan's Technical Specifications to provide reasonable assurance that severe aging degradation will be detected prior to loss of the cable's intended function. Section 18.1.4, Non-EQ Cable Monitoring, in the proposed UFSAR supplement has also been revised to include the use of calibration data in the aging management of these cables.

==

Conclusion:==

Based on the information provided above and the proposed UFSAR supplements attached to this letter, Dominion requests that Open Item 3.9.2-2 be closed.

Open Item 3.9.2-3. If cables are, in fact, simultaneously exposed to significant voltage and moisture then, consistent with the guidance provided in GALL under the third program attribute (Parameters Monitored or Inspected) the cables should be periodically tested or technical basis provided for why they are not.

Dominion Response:

In the LRAs, Dominion identified a medium-voltage cable in the service water system at North Anna that had the potential for wetting, but did not associate the cable with water Page 4

Docket Nos. 50-280/281 50-338/339 Serial No.: 02-360 Page 5 of 8 treeing because the environment of the cable was being maintained in a dry condition.

Subsequent to the initial submittal of the LRAs, additions in the license renewal scope associated with Station Blackout have been made for high-voltage cables that are also subject to potential wetted conditions. Per Dominion's revised response to RAI 2.5-1 (Serial No.02-297 dated July 11, 2002) the cable environment for these high-voltage power cable will also be maintained in the dry condition at both Surry and North Anna.

The Dominion approach to managing the aging mechanism of water treeing is consistent with the staff proposed approach outlined in Section XI.E.3 of the NUREG 1801. Actions, such as inspecting for water collection in cable manholes, and design features such as drains or sump pumps, will be utilized to prevent cables from being exposed to wetted conditions for any significant period of time. Medium or high voltage cables for which such actions are taken are not required to be tested under the second attribute of the NUREG-1801 guidance (Preventative Actions) since operating experience indicates that prolonged exposure to both water and voltage are required to induce this aging mechanism. The Non-EQ Cable monitoring program for Surry and North Anna will be revised to specifically credit the programs necessary to control water in manholes and underground ducts associated with energized power cables.

Additionally, the Corrective Action attribute of the Non-EQ Cable Monitoring Program will be revised to provide for performing appropriate tests of cables determined to have been wetted for a significant period of time. Separate correspondence (Serial No. 02 297 dated July 11, 2002) on this subject provided a supplemental response to RAI 3.6.2-1 which incorporated the requirement for testing of cables subject to significant wetting. The specific type of test performed will be determined prior to the initial test, and is to be a test proven capable of detecting deterioration of the insulation system due to wetting. Test results will be evaluated and will consider the cable age, condition, materials, and cable construction as well as the duration of the exposure to a wetted condition to determine appropriate actions.

Appropriate actions may include replacement or additional testing/inspections to provide reasonable assurance that the power cables would continue to perform their intended functions throughout the period of extended operation.

==

Conclusion:==

Based on the information provided above and the information provided in response to Open Item 2.5-1, Dominion requests that Open Item 3.9.2-3 be closed.

Open Item 4.3-1. The applicant used the results presented in NUREG/CR-6260 (for an older vintage Westinghouse plant) to estimate the impact of the environment on fatigue usage for the NAS and SPS charging and safety injection nozzles.

The applicant should provide an assessment of charging and safety injection nozzles that is directly applicable to NAS and SPS.

Page 5

Docket Nos. 50-280/281 50-338/339 Serial No.: 02-360 Page 6 of 8 Dominion Response:

The requested Surry and North Anna specific assessment of the impact of environmental assisted fatigue on the charging and safety injection nozzles has been provided to the staff in separate correspondence (Serial No.02-332 dated June 13, 2002). This correspondence provides a supplemental response to RAI 4.3-6 regarding this subject.

==

Conclusion:==

Based on this response and the information provided in the above referenced letter, Dominion requests that Open Item 4.3-1 be closed.

Open Item 4.3-2. The applicant should update the FSAR supplement to provide a more detailed discussion of its proposed program to address environmental fatigue effects.

The summary description did not reference WCAP-1 5338. The applicant should include a reference to the WCAP-15338 evaluation in the UFSAR description to provide the technical basis for the TLAA evaluation.

Dominion Response:

The proposed UFSAR supplements provided with this letter as Attachments 3 and 4, incorporate a more detailed discussion of Dominion's program to address environmental assisted fatigue effects.

The program involves the inclusion of the pressurizer surge line inspections into the Augmented Inspection program at both sites. Section 18.2.1, Augmented Inspection Activities, provides the requested additional detail.

Also, the proposed UFSAR supplements provided with this letter add the appropriate Westinghouse document reference to Section 18.3.2.2, Reactor Vessel Underclad Cracking. The document, WCAP-15338, 'A Review of Cracking Associated With Weld Deposited Cladding in Operating PWR Plants," was also included as Reference 21 to the new proposed UFSAR Section 18 reference list.

==

Conclusion:==

Based on the information provided in the above response and the proposed UFSAR supplements, Dominion requests that Open Item 4.3-2 be closed.

Page 6

Docket Nos. 50-280/281 50-338/339 Serial No.: 02-360 Page 7 of 8 Open Item 4.6-1. The staff requests that the licensee resolve the discrepancy between information provided in Table 3.8-7, Section 3.8.2 of the NAS UFSAR, and the NAS LRA. Table 3.8-7 indicates that the NAS containment liner is designed to 100 cycles of operating pressure variations, 400 cycles of operating temperature variations, and design basis earthquake cycles. However, the NAS LRA states that the liner plate is designed for 1,000 cycles of operating pressure variations, 4,000 cycles of temperature variation, and 20 cycles of design basis-earthquake, all simultaneously applied.

Dominion Response:

The values of 100 pressure variation cycles and 400 temperature variation cycles identified in North Anna UFSAR Table 3.8-7 are numbers that represent the anticipated maximum number of cycles for a 40 year operating license. As such, these values were not expected to be exceeded. The actual pressure and temperature design limits for the North Anna containment liners are 1000 cycles and 4000 cycles, respectively, based on the original license period (40 year) calculations. This is the same basis identified for Surry in Section 15.5.1.8 of the current Surry UFSAR.

The implied pressure and temperature cycle limits in North Anna UFSAR Table 3.8-7 were previously identified as unclear and ambiguous information in the review process used to identify required changes to the North Anna UFSAR with regards to license renewal. A revision to North Anna UFSAR Table 3.8-7 will be implemented upon issuance of a renewed operating license. The revision will clarify the "design limit" versus "anticipated" values and will incorporate the revised values for these terms which will include the period of extended operation. An explanation of these revised values is provided in Section 18.3.4 of the proposed UFSAR supplement. (Refer to the response to Open Item 4.6-2.)

==

Conclusion:==

Based on the information provided in the above response and the proposed UFSAR supplements provided with this letter, Dominion requests that Open Item 4.6-1 be closed.

Open Item 4.6-2. The applicant should revise the FSAR supplement to describe the TLAA evaluation of the containment liner plate, including the number of design cycles used for the evaluation of each facility. The applicant's FSAR supplement, provided in Section A3.4 of each LRA, did not indicate that a fatigue evaluation assuming that the number of design cycles were increased by a factor of 1.5 was used to demonstrate that the fatigue of liner plate remained valid for the period of extended operation.

Page 7

Docket Nos. 50-280/281 50-338/339 Serial No.: 02-360 Page 8 of 8 Dominion Response:

Proposed UFSAR supplement Section 18.3.4, Containment Liner Plate, has been revised to include the discussion of the extrapolation of cycles to 60-years of operation and clearly establishes the design limits for operating pressure and temperature variations as 1500 and 6000, respectively. The anticipated operating cycle values were extrapolated to 150 (pressure) and 600 (temperature). The extrapolation was based on a simple increase of the current 40-year values by a factor of 1.5 to account for the period of extended operation.

Section 18.3.4 has also been revised to provide a discussion of the difference between the number of anticipated cycles and the design limits for cycles for both pressure and temperature operating variations for both stations. These extrapolated anticipated and design limit values for the pressure and temperature variations are included in the proposed UFSAR changes to Table 3.8-7 for North Anna and Section 15.5.1.8 for Surry.

==

Conclusion:==

Based on the information provided in the above response and the proposed UFSAR supplements provided with this letter, Dominion requests that Open Item 4.6-2 be closed.

Page 8

Docket Nos. 50-280/281 50-338/339 Serial No.: 02-360 Page 1 of 9 License Renewal - Disposition of Draft SER Confirmatory Actions Serial No.02-360 Surry and North Anna Power Stations, Units 1 and 2 License Renewal Virginia Electric and Power Company (Dominion)

Page 1

Docket Nos. 50-280/281 50-338/339 Serial No.: 02-360 Page 2 of 9 Disposition of Draft SER Confirmatory Actions Surry and North Anna Power Stations Confirmatory Action 2.3.1.2-1. The applicant in its January 4, 2002, letter informed the staff that the license renewal drawings referenced in the applications (1 1448-LRM 086A, sh. 1, and 11548-LRM-086A, sh. 1, for Surry and 11715-LRM-093A, sh. 1, and 12050-LRM-093A, sh. 1 for North Anna) incorrectly indicate the leak detection components within the scope of license renewal. The applicant committed to revise the affected license renewal drawings consistent with this justification.

STA TUS:

This action is complete. The listed drawings have been revised to remove the reactor vessel flange leak detection system from the scope of license renewal.

Confirmatory Action 3.3.1.1-1. In its response to RAI B2.2.9-3, the applicant states that it will incorporate the followup actions from Table B4.0-1 of each LRA into the UFSAR supplements for the Surry and North Anna Power Stations. The applicant commits to describe the followup actions in the appropriate aging management activity summaries provided in UFSAR supplement of the applications. The staff finds these proposed modifications to the Section A2.2.1 of the UFSAR supplement to be acceptable.

STATUS:

This action is complete. All items originally in Table B4.0-1 of the LRAs have been incorporated into the text of their respective Aging Management Activities (AMAs) in the proposed UFSAR supplement. This includes the Augmented Inspection Activities in proposed UFSAR supplement Section 18.2. 1.

Confirmatory Action 3.3.1.6-1. In response to RAI 3.5-7, the applicant has committed to credit the civil engineering structural inspection activity to manage change in material properties and the previously cited aging effects cracking and loss of material for concrete structures.

This additional aging effect for concrete structures should be added to Section A2.2.6 of the UFSAR supplement.

Page 2

Docket Nos. 50-280/281 50-338/339 Serial No.: 02-360 Page 3 of 9 STATUS:

This action is complete.

Proposed UFSAR supplement Section 18.2.6, Civil Engineering Structural Inspections, has been modified to include change in material properties as an aging effect for both concrete and elastomer sealant and/or gasket materials.

Confirmatory Action 3.3.1.7-1.

In response to RAI B2.2.9-3, the applicant states that it will incorporate the followup actions from Table B4.0-1 of each LRA into the UFSAR supplements in each LRA. The applicant commits to describe the followup actions in the appropriate aging management activity summaries provided in Appendix A of the applications.

STATUS:

This action is complete. All items originally in Table B4.0-1 of the LRAs have been incorporated into the text of their respective AMAs in the proposed UFSAR supplement.

This includes the Fire Protection Program in proposed UFSAR supplement Section 18.2.7.

Confirmatory Action 3.3.1.7-2.

In its response to RAI B2.2.7-2 in a letter to the NRC dated November 30, 2001, the applicant states that it will supplement the NFPA pressure and flowrate testing credited in each LRA as part of the fire protection program activity with the work control process activity in order to manage aging effects for the fire protection system piping. This commitment by the applicant should be incorporated into Section A2.2.7 of the UFSAR supplement.

S TA TUS:

This action is complete. Proposed UFSAR supplement Section 18.2.7, Fire Protection Program, has been modified to credit the Work Control Process.

Confirmatory Action 3.3.1.9-1.

In its response to RAI B2.2.9-3, in a letter dated November 30, 2001, the applicant states that it will incorporate the licensee followup actions from Table B4.0-1 of each LRA into the UFSAR supplements for the Surry and North Anna Power Stations. The applicant commits to describe the followup actions in Page 3

Docket Nos. 50-280/281 50-338/339 Serial No.: 02-360 Page 4 of 9 the appropriate Aging Management Activities summaries provided in Appendix A of the applications STATUS:

This action is complete. All items originally in Table B4.0-1 of the LRAs have been incorporated into the text of their respective AMAs in the proposed UFSAR supplement.

This includes General Condition Monitoring in proposed UFSAR supplement Section 18.2.9.

Confirmatory Action 3.3.10-1. In Section B2.2.10 of the LRA, the applicant commits to a followup action that is not discussed in the UFSAR supplement. The licensee followup action is to implement a one-time internal inspection of a representative sample of the box girders for the polar cranes. The inspection will be performed between year 30 and the end of the current operating license. This item is included in each LRA, Table B4.0 1, which contains a comprehensive list of followup action items, but is not discussed in Section A2.2.10 of the UFSAR supplement. In its response to RAI B2.2.9-3, in a letter dated November 30, 2001, the applicant states that it will incorporate the licensee followup actions from Table B4.0-1 of each LRA into the UFSAR supplements for the Surry and North Anna Power Stations. The applicant commits to describe the followup actions in the appropriate Aging Management Activity summaries provided in Appendix A of the applications.

STATUS:

This action is complete. All items originally in Table B4.0-1 of the LRAs have been incorporated into the text of their respective AMAs.

Proposed UFSAR supplement Section 18.2.10, Inspection Activities - Load Handling Cranes and Devices, has been modified to include the box girder inspections.

Confirmatory Action 3.3.1.11-1.

In Section B2.2.11 of each LRA, the applicant commits to a followup action that is not discussed in the UFSAR supplement.

This followup action commits the applicant to follow industry activities related to failure mechanisms for small-bore piping and evaluate changes to inspection activities based on industry experience. This item is included in each LRA, Table B4.0-1, which contains a comprehensive list of followup action items, but is not discussed in Section A2.2.11 of the UFSAR supplement. In response to RAI B2.2.9-3, the applicant states that it will incorporate the licensee followup actions from Table B4.0-1 of each LRA into the UFSAR supplements for the Surry and North Anna Power Stations. The applicant Page 4

Docket Nos. 50-280/281 50-338/339 Serial No.: 02-360 Page 5 of 9 commits to describe the followup actions in the appropriate Aging Management Activity summaries provided in Appendix A of the applications.

STATUS:

This action is complete. All items originally in Table B4.0-1 of the LRAs have been incorporated into the text of their respective AMAs.

Proposed UFSAR supplement Section 18.2.11, ISI Program - Component and Component Support Inspection, has been modified to include the use of industry activities and guidance related to small bore piping issues and inspections.

Confirmatory Action 3.3.1.12-1. In response to RAI 3.5-3, the applicant states that it will credit the examinations required by ASME Section Xl, Subsection IWL, Examination Category L-A to manage the potential aging effects of concrete structural members of the containment and that these examinations will be added to the ISI program for containment inspection aging management activity. The applicant further states that the response to this RAI will require changes to the UFSAR supplement that will be presented to the NRC staff in a future revision.

STATUS:

This action is complete. Proposed UFSAR supplement Section 18.2.12, ISI Program Containment Inspection, has been revised to incorporate ASME Section XI, Subsection IWL.

Confirmatory Action 3.3.1.19-1. Section A2.2.19 of each LRA includes two boxed items related to "water treeing." Similar information is not included in Section B2.2.19 of either LRA. The applicant stated (during August 28, 2001, telecommunication as documented in telecommunication summary dated October 11, 2001) that this was an administrative error and the two boxed items relating to "water treeing" should not have been included in Section A2.2.19. The applicant further stated that the staff should not consider this information during its evaluation. The applicant needs to revise the UFSAR supplement accordingly or include similar information in Section B2.2.19 of each LRA.

Page 5

Docket Nos. 50-280/281 50-338/339 Serial No.: 02-360 Page 6 of 9 STATUS:

Draft SER Section 3.3.1.19.4, FSAR supplement, identified six areas for proposed UFSAR supplement revision. Each identified change is addressed as follows:

1. The Licensee Follow-up Action for changes to maintenance procedures to assure consistent internal inspections has been added to Section 18.2.19 of the proposed UFSAR supplement. This action is complete.

2. RAI Responses 2.1-3, B2.2.7-2 and B2.2.19-3 identified a number of additional systems and components added to the scope of the work control process. In the draft SER, the staff requested that the proposed UFSAR supplement be revised to identify these added systems for which the work control process is credited. The systems and components originally identified in the LRAs for which the work control process was credited were not identified in the proposed UFSAR supplement provided as Appendix A to the LRAs. This level of detail in the proposed UFSAR supplement is consistent with the aging management program description requirements of NUREG-1800, Standard Review Plan for license renewal. Also, adding a list of applicable systems to Section 18.2.19 of the proposed UFSAR supplement would be inconsistent with the other aging management program descriptions in the proposed UFSAR supplement.

The systems identified as expanded scope or as new scope systems identified in the response to RAI 2.1-3 were documented in a license renewal technical report. This document will be one of the basis documents used in the periodic auditing of the scope of the work control process, as committed to in RAI Response B2.2.19-3.

This commitment to audit has been incorporated into the proposed UFSAR supplement. (Reference Item #3 below.) The Response to RAI B2.2.19-3 also credited the work control process for the fire protection system. This commitment has also been incorporated into the proposed UFSAR supplement. (Refer to Confirmatory Action 3.3.1.7-2.) Therefore, no additional revisions to the proposed UFSAR supplement are required to address this issue.

3. RAI responses made a commitment to audit the work control process at years 40 and 50 and to perform supplemental inspections, as necessary, within 5 years. This commitment has been incorporated into Section 18.2.19 of the proposed UFSAR supplement. The audit will ensure that all systems and components for which the work control process was credited, including all systems identified in RAI responses, will be represented in the program. This action is complete.

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Docket Nos. 50-280/281 50-338/339 Serial No.: 02-360 Page 7 of 9

4. RAI responses made a commitment that if aging identified in a location within a system cannot be explained by environmental/operational conditions at that location, an inspection of similar material/environmental components, both within and outside the system, would be performed. This commitment has been incorporated into Section 18.2.19 of the proposed UFSAR supplement. This action is complete.

5. RAI responses withdrew the use and reference to EPRI report TR-107514. No reference to this report was made in the proposed UFSAR supplement (Appendix A) which accompanied the LRAs.

Therefore, there is no revision to the proposed UFSAR supplement necessary. No additional action is required.

6. The USFAR supplement has been revised to remove the boxed areas (North Anna specific information) for water treeing from the Work Control Process AMA in Section 18.2.19. However, water treeing is addressed the proposed UFSAR supplement in Section 18.1.4, Non-EQ Cable Monitoring program. This action is complete.

Confirmatory Action 3.3.3.2-1.

The applicant references the transient cycle counting program (TCCP) in its discussion of the fatigue TLAAs as a method to manage the fatigue usage of reactor coolant pressure boundary components. Pending resolution of the open items 4.3-1 and 4.3-2 of this SER, the staff considers the applicant's program to be acceptable for managing the fatigue TLAA during the period of extended operation.

STATUS:

This action of accepting the Transient Cycle Counting Program, (proposed UFSAR supplement Section 18.4.2) is complete pending closure of Open Items 4.3-1 and 4.3-2.

[See Attachment 1 Open Items 4.3-1 and 4.3-2] The following actions have been completed:

1. The Surry and North Anna specific assessment of the impact of environmental assisted fatigue on the charging and safety injection nozzles requested in Open Item 4.3-1 has been provided to the staff in separate correspondence (Serial No.02-332 dated June 13, 2002).

2. The Surry and North Anna proposed UFSAR supplements provided with this letter as Attachments 3 and 4, respectively, have been revised to provide a more detailed discussion of Dominion's program to address environmental assisted fatigue effects in response to Open Item 4.3-2.

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Docket Nos. 50-280/281 50-338/339 Serial No.: 02-360 Page 8 of 9

3. Also, in response to Open Item 4.3-2, the Surry and North Anna proposed UFSAR supplements have been revised to add the appropriate Westinghouse document reference to Section 18.3.2.2, Reactor Vessel Underclad Cracking.

The document, WCAP-15338, "A Review of Cracking Associated With Weld Deposited Cladding in Operating PWR Plants," was also included as Reference 21 to the proposed UFSAR Section 18 reference list.

Confirmatory Action 3.3.4.2-1.

In its response to RAIs 3.5-1 and 3.5-7, the applicant needs to clarify that the infrequently accessed area inspection activities will be revised to include management of these two additional aging effects (cracking and change in material properties). In its response to both RAIs, the applicant acknowledged that their responses will require changes to the UFSAR supplement and committed to submit these changes to the NRC staff in a future revision.

STATUS:

This action is complete. Proposed UFSAR supplement Section 18.1.2, Infrequently Accessed Area Inspection Activities, has been modified to include cracking and change in material properties as aging effects requiring management for concrete.

Confirmatory Action 3.8.1-1. The applicant does not provide a technical basis for ensuring that the groundwater remains non-aggressive during the period of extended operation.

In RAI 3.5-2, the staff requested that the applicant indicate what method (e.g., periodic monitoring of groundwater chemistry) will be used to ensure that the groundwater remains non-aggressive during the period of extended operation.

In response, the applicant stated that there are currently not enough historical groundwater sampling data available to develop a groundwater chemistry trend. Once incorporated, as committed in this response, the staff considers this issue to be resolved.

STA TUS:

This action is complete.

Proposed UFSAR supplement Section 18.2.6, Civil Engineering Structural Inspections, has been modified to include annual monitoring of groundwater chemistry.

Additionally, Section 18.2.6 requires that groundwater chemistry be considered as part of engineering evaluations of inspection results.

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Docket Nos. 50-280/281 50-338/339 Serial No.: 02-360 Page 9 of 9 Confirmatory Action 3.8.1-2. The applicant's response to RAI 3.5-1 will require changes to the UFSAR supplement that will be presented to the NRC staff in a future revision. In RAI 3.5-1, the staff requested that the applicant provide justification for not including an aging management review of the de-watering system for control of hydrostatic pressure to the containment liner plate. Furthermore, if a de-watering system is relied on for control of hydrostatic pressure, then the de-watering system needs to be included within the scope of license renewal and subject to an aging management review. Once incorporated, as committed in its response, the staff considers this issue to be resolved.

STA TUS:

This action is complete. The subsurface drainage system around the containments have been incorporated into the license renewal scope for both Surry and North Anna.

Proposed UFSAR supplement Section 18.1.2, Infrequent Accessed Area Inspection Activities, has been modified to include the structures associated with these systems.

The Work Control Process, proposed UFSAR supplement Section 18.2.19, encompasses the mechanical portions of the system.

Confirmatory Action 3.8.2-1. The staff finds the applicant's response to RAI 3.5.8-2 to be acceptable, except for loss of form due to sedimentation (sludge) buildup in the North Anna Service Water Reservoir (SWR). The applicant states that up to 4 feet of sludge buildup can be tolerated before loss of function. In addition, the applicant stated that through 20 years of operation one foot of sludge buildup has occurred in the SWR.

Using linear extrapolation, there would be 3 feet of sludge buildup after 60 years.

However, there is no specific basis for linear extrapolation. Considering the relatively small margin for error, a one-time inspection prior to entering the period of extended operation would be appropriate.

In discussing its response to RAI 3.5.8-2 with the applicant in November 14, 2001, the applicant committed to do a one-time inspection of the North Anna SWR to determine the level of sludge buildup.

STA TUS:

This action is complete. Proposed UFSAR supplement Section 18.2.17, Service Water System Inspections, has been modified to include the required sludge buildup measurement.

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Docket Nos. 50-280/281 50-338/339 Serial No.: 02-360 Page 1 of 34 License Renewal - Revised Surry UFSAR Supplement Serial No.02-360 Surry Power Station, Units I and 2 License Renewal Virginia Electric and Power Company (Dominion)

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Surry Power Station, Units 1 and 2 Application for Renewed Operating Licenses Revised UFSAR Supplement CHAPTER 18 18.0 PROGRAMS AND ACTIVITIES THAT MANAGE THE EFFECTS OF AGING The integrated plant assessment for license renewal identified new and existing aging management programs necessary to provide reasonable assurance that components within the scope of license renewal will continue to perform their intended functions consistent with the current licensing basis (CLB) for the period of extended operation. This chapter describes these programs and their planned implementation.

This chapter also discusses the evaluation results for each of the plant-specific time-limited aging analyses (TLAA's) performed for license renewal. The evaluations have demonstrated that the analyses remain valid for the period of extended operation; the analyses have been projected to the end of the period of extended operation; or that the effects of aging on the intended function(s) will be adequately managed for the period of extended operation.

18.1 New Aging Management Activities 18.1.1 Buried Piping and Valve Inspection Activities Prior to the period of extended operation, buried piping and valves will be inspected for the existence of aging effects. The Buried Piping and Valve Inspection Activities will include a one-time inspection of representative samples of piping and valves for different combinations of buried material and burial condition. Visual inspections will be used to detect cracking of protective coatings and loss of material from protective coatings or the substrate material. Visual inspections will also be used to detect gross indications of change in material properties for copper-nickel pipe.

The inspection will be completed between year 30 and 40 of operation and will include representative valves and sample lengths (i.e., several feet) of piping for each of the following combinations of material and burial conditions:

• Carbon steel, concrete encased

• Carbon steel, coated

• Carbon steel, coated, wrapped

• Carbon steel, coated, and wrapped with cathodic protection

• Stainless steel, coated, and wrapped

• 90/10 Copper-nickel, uncoated An engineering evaluation of the results of the buried piping and valves inspections will be performed to determine future actions. Corrective actions for conditions that are adverse to quality are performed in accordance with the Corrective Action System. Corrective Page 2

Surry Power Station, Units 1 and 2 Application for Renewed Operating Licenses Revised UFSAR Supplement action provides reasonable assurance that conditions adverse to quality are promptly corrected.

18.1.2 Infrequently Accessed Area Inspection Activities The purpose of the Infrequently Accessed Area Inspection Activities is to provide reasonable assurance that equipment and components within the scope of License Renewal, which are not readily accessible, will continue to fulfill their intended functions during the period of extended operation. A one-time inspection will be performed between year 30 and 40 of operation to assess the aging of components and structures located in areas not routinely accessed due to high-radiation, high-temperature, confined spaces, location behind security or missile barriers, or normally flooded. The external condition of structures, supports, piping, and equipment will be determined by visual inspection.

These inspections would detect the aging effect of loss of material. In addition, concrete will be inspected to detect the aging effects of loss of material, cracking, and change in material properties.

Infrequently accessed areas determined to be within the scope of license renewal and the focus of inspections within these area include:

• Reactor containment - Sump areas, cabling and supports*

• Reactor containment keyway - Leakage, structural support provided by the neutron shield tank.

• Subsurface drains - Access shaft and component supports

• Cover for Containment dome plug - Structural condition

• Volume control tank (VCT) cubicle - Structure, supports, and equipment.

• Black Battery Building - Supports that could affect power supply to AMSAC

• Cable spreading rooms, Cable tunnels, Upper areas of emergency switchgear rooms Cable raceways and supports*

• New fuel storage area - Supports and structure affecting spent fuel pool cooling*

• Auxiliary Building filter and ion exchanger cubicles - Structure, supports, and equipment*

• Tunnel from Turbine Building to Auxiliary Building - Structure, supports, and piping*

Note: Representative samples will be inspected in areas denoted with an asterisk.

Inspection results will be documented for evaluation and retention. Engineering evaluation assesses the severity of the visual inspection results and determines the extent of required actions or future inspections. Corrective actions for conditions that are adverse to quality are performed in accordance with the Corrective Action System.

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Surry Power Station, Units 1 and 2 Application for Renewed Operating Licenses Revised UFSAR Supplement Corrective action provides reasonable assurance that conditions adverse to quality are promptly corrected.

18.1.3 Tank Inspection Activities The purpose of the Tank Inspection Activities is to perform inspections of above ground and underground tanks to provide reasonable assurance that the tanks will perform their intended function through the period of extended operation.

A one-time inspection will be performed between year 30 and 40 of operation for specified tanks that are within the scope of license renewal and could experience aging effects. The aging effect of concern for tanks is loss of material. A representative sample of tanks will be designated for the one-time inspections in order to assess the condition of tanks that require aging management. The choice of representative tanks to be inspected is dependent on the material of construction for the tank, its contents, the foundation upon which the tank is based, and the type of coating. Visual inspections of internal and external surfaces will be performed. Volumetric examinations will be performed to look for indications of wall thinning on tanks that are founded on soil or buried. Indications of degradation will be referred for evaluation by engineering.

The following tanks will be inspected or represented by suitable replacement samples:

• Emergency diesel generator tanks (fuel oil, coolant, and starting air)

• AAC diesel generator tanks (fuel oil, coolant and starting air)

• Security diesel generator tank (fuel oil)

• Underground fuel oil storage tanks

• Diesel-driven fire pump fuel oil storage tanks

• Refueling water storage tanks

• Chemical addition tanks

• Emergency condensate storage tanks

• Fire Protection / Domestic water storage tank

• Emergency service water pump diesel fuel oil storage tank An engineering evaluation may determine that the observed condition is acceptable or requires repair; or, in the case of degraded coatings, may direct removal of the coating, non-destructive examination of the substrate material, and replacement of the coating.

Re-inspections will be dependent upon the observed surface condition, and the results of this engineering evaluation. Corrective actions for conditions that are adverse to quality are performed in accordance with the Corrective Action System. Corrective action provides reasonable assurance that conditions adverse to quality are promptly corrected.

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Surry Power Station, Units 1 and 2 Application for Renewed Operating Licenses Revised UFSAR Supplement 18.1.4 Non-EQ Cable Monitoring The purpose of the Non-EQ Cable Monitoring activities will be to perform inspections on a limited, but representative, number or accessible cable jackets and connector coverings that are utilized in non-EQ applications. In order to confirm that ambient conditions are not changing sufficiently to lead to age-related degradation of the in-scope cable jackets and connector coverings, initial visual inspections for the non-EQ application insulated power cables, instrumentation cables, and control cables (including low-voltge instrumentation and control cables that are sensitive to a reduction in insulation resistance) will be performed between year 30 and 40 of operation. Visual inspection of the representative samples of non-EQ power, instrumentation, and control cable jackets and connector coverings will detect the presence of cracking, discoloration, or bulging, which could indicate aging effects requiring management. These effects could be due to high radiation, high temperature, or wetted condition environments. Subsequent inspections to confirm ambient conditions will be performed at least once per 10 years following the initial inspection.

The potentially adverse localized environment due to moisture which could lead to water-treeing in high-or medium-voltage cables that are within the scope of license renewal, is also detected by visually monitoring for the presence of water around cables.

Programs utilizing periodic inspections and design features such as drains or sump pumps are used to control the cable localized environment. Cable found to be wetted for any significant period of time will be tested using an appropriate test method which has been proven to accurately assess the cable condition with regards to water treeing.

The source, intermediate, and power range neutron detector operate with high-voltage power supply in conjunction with low-voltage signal cables. The routine calibration of these detectors will be used to identify the potential existance of aging degradation in the associated cables.

Any anomalies resulting from the inspections will be dispositioned by Engineering and will consider the cable environment including the potential for moisture in the areas of the anomolies. Occurrence of an anomaly that is adverse to quality will be entered into the Corrective Action System. The corrective action process provides reasonable assurance that deficiencies adverse to quality are either promptly corrected or are evaluated to be acceptable. Although age-related degradation is not expected for power, instrumentation, and control cables and connectors in their normal environments, visual inspections will provide reasonable assurance that the intended functions will be maintained.

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Surry Power Station, Units 1 and 2 Application for Renewed Operating Licenses Revised UFSAR Supplement 18.2 Existing Aging Management Activities 18.2.1 Augmented Inspection Activities The purpose of the Augmented Inspection Activities is to perform examinations of selected components and supports in accordance with requirements identified in the Technical Specifications, UFSAR, license commitments, industry operating experience, and good practices for the station. Augmented inspections are outside the required scope of ASME Section XI. The scope of Augmented Inspection Activities to be performed during each refueling outage is identified by Engineering in accordance with controlled procedures. Component conditions are monitored to detect degradation due to loss of material and cracking. Inspections include visual, surface, and volumetric examinations.

The extent of each component inspection is defined within the Augmented Inspection Activities program description.

Augmented Inspection Activities include:

"* Sensitized stainless steel (Class 1) circumferential, longitudinal, branch connection, and socket welds on for the Pressurizer spray line welds in the RC System.

"* Sensitized stainless steel (Class 2) circumferential, longitudinal, branch connection, and socket welds on the SI, and CS systems.

• High Energy Lines Outside of Containment (Main Steam and Feedwater)

• Reactor vessel incore detector thimble tubes

• Component supports

• Steam generator feedwater nozzles

• Pressurizer instrument connections

• Reactor vessel head The Augmented Inspection Activities will also include an inspection of the core barrel hold-down spring. The inspection will address the aging effect of loss of pre-load. The initial inspection will be performed prior to the end of year 40 of operation. Additionally, Augmented Inspection Activities will include an inspection of the pressurizer surge line connection to the reactor coolant system hot-leg loop piping. The inspection will address the aging effect of thermal fatigue failure of the weld due to environmental effects, as described in NRC Generic Safety Issue GSI-190. Inspection details regarding scope, frequency, qualifications, methods, etc. will be submitted to the NRC. The initial inspection will be completed prior to the end of year 40 of operation. Additional inspections will be performed during each subsequent inspection period. Industry efforts to study the environmental effects on weld thermal fatigue failure will continue to be evaluated by Dominion. If warranted, alternatives to this planned inspection (re-evaluation, replacement, or repair) will be submitted to the NRC.

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Surry Power Station, Units 1 and 2 Application for Renewed Operating Licenses Revised UFSAR Supplement The acceptance standards for non-destructive examinations for the Augmented Inspection Activities are consistent with guidance provided in ASME Section Xl or are provided within applicable examination procedures. Evidence of loss of material, loss of pre-load, or cracking requires engineering evaluation for determination of corrective action. Occurrence of significant degradation that is adverse to quality will be entered into the Corrective Action System. Corrective action provides reasonable assurance that conditions adverse to quality are promptly corrected.

18.2.2 Battery Rack Inspections The purpose of the Battery Rack Inspections is to provide reasonable assurance of the integrity of the supports for various station batteries. Loss of material due to corrosion is the aging effect. Periodic checks of the rack integrity are performed, coincident with periodic battery inspections, to determine the physical condition of the battery support racks. The condition and mechanical integrity of the battery support racks are visually inspected to provide reasonable assurance that their function to adequately support the batteries is maintained. Visual inspections are adequate to identify degradation of the physical condition of the support racks. These inspections check for corrosion of the support rack structural members.

If any material condition deterioration is sufficiently extensive to interfere with integrity of the racks, the Corrective Action System will determine the cause and appropriate action to repair and prevent recurrence of the degradation. Corrective action provides reasonable assurance that conditions adverse to quality are promptly corrected.

18.2.3 Boric Acid Corrosion Surveillance Leakage from borated systems inside Containment creates the potential for degradation of components. Inspections are performed to provide reasonable assurance that borated water leakage does not lead to undetected loss of material from the reactor coolant pressure boundary and surrounding components. Carbon steel is particularly susceptible, but copper also can be damaged.

In Generic Letter 88-05 (Reference 2), the NRC identified concerns with boric acid corrosion of carbon-steel reactor pressure boundary components inside Containment. In response to this generic letter, activities were developed to examine primary coolant components for evidence of borated water leakage that could degrade the external surfaces of nearby structures or components, and to implement corrective actions to address coolant leakage.

Primary coolant systems inside Containment are examined for evidence of borated water leakage. An overall visual inspection of coolant system piping is performed, with particular interest in potential leakage locations. Insulated portions of the coolant systems are examined for signs of borated water leakage through the insulation by examining Page 7

Surry Power Station, Units 1 and 2 Application for Renewed Operating Licenses Revised UFSAR Supplement accessible joints and exposed surfaces of piping and equipment. Vertical components are examined at the lowest elevation. Components and connections that are not accessible are examined by looking for borated water leakage on the surrounding area of the floor or adjacent equipment and insulation. The inspection scope includes connections to the reactor coolant system from the normal coolant letdown and makeup piping, and from the emergency core cooling systems. Components that are in the vicinity of borated water leakage are also examined for damage resulting from the leakage.

The acceptance criterion for visual inspections is the absence of detectable leakage or boric acid residue. Whenever evidence exists of borated water leakage, a visual examination is required, and an engineering evaluation is performed to determine whether degradation of the leaking component or nearby affected components has occurred; and whether the observed condition is acceptable without repair. Occurrence of significant degradation that is adverse to quality is entered into the Corrective Action System. Corrective action provides reasonable assurance that conditions adverse to quality are promptly corrected.

18.2.4 Chemistry Control Program for Primary Systems The purpose of the Chemistry Control Program for Primary Systems is to provide reasonable assurance that water quality is compatible with the materials of construction in the plant systems and equipment in order to minimize the loss of material and cracking.

The Chemistry Control Program for Primary Systems creates an environment in which material degradation is minimized, therefore, maintaining material integrity and reducing the amount of corrosion product that could accumulate and interfere with equipment operation or heat transfer.

Chemistry sampling is performed and the results are monitored and trended by maintaining logs of measured parameters. Acceptability of the measurements is determined by comparison with the limits established in the Chemistry Control Program for Primary Systems. Acceptance criteria for the measured primary chemistry parameters are listed in the Chemistry Control Program for Primary Systems. The acceptance criteria reflect EPRI guidelines for parameters that have been shown to contribute to component degradation. Adherence to the guidelines minimizes the aging effects of loss of material and cracking.

Action levels are established to initiate corrective action when the established limits are approached or exceeded. Depending on the magnitude of the out-of-limit condition, plant shutdown may be performed to minimize aging effects while plant actions are being taken. Corrective actions for conditions that are adverse to quality are performed in accordance with the Corrective Action System. Corrective action provides reasonable assurance that conditions adverse to quality are promptly corrected.

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Surry Power Station, Units 1 and 2 Application for Renewed Operating Licenses Revised UFSAR Supplement 18.2.5 Chemistry Control Program for Secondary Systems The purpose of the Chemistry Control Program for Secondary Systems is to provide reasonable assurance that water quality is compatible with the materials of construction in the plant systems and equipment in order to minimize the loss of material and cracking.

The Chemistry Control Program for Secondary Systems creates an environment in which material degradation is minimized, therefore, maintaining material integrity and reducing the amount of corrosion product that could accumulate and interfere with equipment operation or heat transfer.

Chemistry results are monitored and trended by maintaining logs of measured parameters. Acceptability of the measurements is determined by comparison with limits established by the Chemistry Control Program for Secondary Systems. Acceptance criteria for the measured secondary chemistry parameters are listed in the Chemistry Control Program for Secondary Systems. The acceptance criteria reflect EPRI guidelines for parameters that have been shown to contribute to component degradation. Adherence to the guidelines minimizes the aging effects of loss of material and cracking.

Action levels are established to initiate corrective action when the established limits are exceeded. Depending on the magnitude of the out-of-limit condition, power is reduced or the plant is shut down to minimize aging effects while plant actions are being taken.

Corrective actions for conditions that are adverse to quality are performed in accordance with the Corrective Action System. Corrective action provides reasonable assurance that conditions adverse to quality are promptly corrected.

18.2.6 Civil Engineering Structural Inspection The maintenance rule, 10 CFR 50.65, requires licensees to monitor the condition of structures against established goals. During the period of extended operation, the provisions of the Maintenance Rule Program will be utilized to provide reasonable assurance of the continuing capability of civil engineering structures to fulfill their intended functions. The scope of Civil Engineering Structural Inspections will be expanded to include inspections required for license renewal, including annual monitoring of groundwater chemistry. This expansion will be implemented prior to the end of year 40 of operation.

Structural monitoring inspections are visual inspections that are performed to assess the overall physical condition of the structure. For concrete structures, this includes elastomer sealant and gasket materials.

Inspections are performed by trained inspectors and include representative samples of both the interior and exterior accessible surfaces of structures. Documentation of inspection results includes a general description of observed conditions, location and size of anomalies, and the noted effects of environmental conditions. If an inaccessible area Page 9

Surry Power Station, Units 1 and 2 Application for Renewed Operating Licenses Revised UFSAR Supplement becomes accessible by such means as dewatering, excavation or installation of radiation shielding, an opportunity will exist for additional inspections. Prior to the end of year 40 of operation, guidance will be provided in plant procedures to take advantage of such inspection opportunities when they arise for inaccessible areas.

A visual indication of: 1) loss of material for concrete and structural steel, 2) significant cracking for concrete and masonry walls, 3) change in material properties for elastomers,

4) loss of material or loss of form for soil, and 5) gross indications of change in material properties of concrete, each requires an engineering evaluation.

Inspections of masonry walls are included in this program. The inspections check for cracks of joints and missing or broken blocks.

The engineering evaluation of inspection results, including groundwater chemistry results, determines whether analysis, repair, or additional inspections or testing is required to provide reasonable assurance that structures will continue to fulfill their intended functions. Corrective actions for conditions that are adverse to quality are performed in accordance with the Corrective Action System. Corrective action provides reasonable assurance that conditions adverse to quality are promptly corrected.

18.2.7 Fire Protection Program Regulatory requirements associated with fire protection systems and implementation plans are provided in 10 CFR 50.48 and 10 CFR 50, Appendix R. The Fire Protection Plan includes applicable National Fire Protection Association commitments and maintains compliance with NRC Branch Technical Position (BTP) 9.5-1 from the Standard Review Plan (Reference 3). Aging management concerns related to fire protection involve visual inspections of fire protection equipment and barriers, including doors, walls, floors, ceilings, penetration seals, fire-retardant coatings, fire dampers, cable-tray covers, and fire stops.

Applicable aging effects that are found by visual examination include loss of material, separation and cracking/delamination, heat transfer degradation, and change in material properties. Aging effects on piping systems (including valve bodies and pump casings) that are dry or that carry water are evaluated in the same manner as for any other mechanical system. Testing of the fire protection pumps provides indication of heat transfer degradation, and inspections of the pumps provide indication of loss of material.

Verification of piping integrity to maintain a pressure boundary for the fire protection system, and the availability of water are addressed by routine plant walkdowns, by pressure/flow tests that are conducted periodically, and by the Work Control Process.

Visual inspections are performed periodically for hose stations, hydrants, and sprinklers.

Provisions to replace sprinklers or test a representative sample of sprinklers that have been in service for 50 years will be incorporated into the Fire Protection Program. This Page 10

Surry Power Station, Units 1 and 2 Application for Renewed Operating Licenses Revised UFSAR Supplement task conforms to the requirements of NFPA-25, Section 2-3.1.1. If testing is performed, re-testing will be performed at 10 year intervals per NFPA-25.

Fire protection equipment is examined for indications of visible damage. Acceptable sizes for breaks, holes, cracks, gaps, or clearances in fire barriers, and acceptable amounts of sealant in penetrations are established in the inspection procedures. Any questions regarding the ability of the barrier to fulfill its fire protection function are addressed by engineering evaluation. Acceptance criteria for fire protection equipment performance tests (i.e., flow and pressure tests) are provided in the appropriate test procedures.

Occurrence of significant degradation that is adverse to quality is entered into the Corrective Action System. Corrective action provides reasonable assurance that conditions adverse to quality are promptly corrected.

18.2.8 Fuel Oil Chemistry The Fuel Oil Chemistry program manages the loss of material by requiring that oil quality is compatible with the materials of construction in plant systems and equipment. Poor fuel oil quality could lead either to degradation of storage tanks or accumulations of particulates or biological growth in the tanks. The purpose of the Fuel Oil Chemistry program is to minimize the existence of contaminants such as water, sediment, and bacteria which could degrade fuel oil quality and damage the fuel oil system and interfere with the operation of safety-related equipment.

The Fuel Oil Chemistry program is an aging effects mitigation activity which does not directly detect aging effects. The Fuel Oil Chemistry guidelines address the parameters to be monitored and the acceptance limit for each parameter. The acceptance criteria reflect ASTM guidelines for parameters that have been shown to contribute to component degradation. Adherence to the guidelines mitigates the aging effect of loss of material.

Parameters analyzed and found to be outside established limits will be reported to Engineering, an evaluation will be performed, and appropriate corrective actions will be taken. Occurrence of significant deviations that are adverse to quality is entered into the Corrective Action System. Corrective action provides reasonable assurance that conditions adverse to quality are promptly corrected.

18.2.9 General Condition Monitoring Activities General Condition Monitoring Activities are performed for the assessment and management of aging for components that are located in normally accessible areas. The results of this monitoring are the basis for initiating required corrective action in a timely manner. This monitoring is based on the observations that are made during focused inspections that are performed on a periodic basis. Guidance will be developed and implemented in procedures for engineers and health physics technicians regarding inspection criteria that focus on detection of aging effects during General Condition Page 11

Surry Power Station, Units 1 and 2 Application for Renewed Operating Licenses Revised UFSAR Supplement Monitoring Activities. This guidance will be provided prior to the end of year 40 of operation.

The external condition of supports, piping, doors, and equipment will be determined by visual inspection. General Condition Monitoring Activities are performed in three different ways:

• Inspections of radiologically controlled areas for borated water leakage

• Periodic focused inspections such as system walkdowns

• Area inspections for condition of structural supports and doors Inspection criteria for non-ASME Section XI component supports and doors, as part of General Condition Monitoring, will be developed. Initial inspections will be completed, using the criteria, prior to the end of year 40 of operation.

These inspections provide information to manage the aging effects of loss of material, change in material properties, separation and cracking/delamination, and cracking.

The acceptance criteria for visual inspections are identified in procedures that direct the various monitoring activities. Responsibility for the evaluation of identified visual indications of aging effects is assigned to Engineering personnel. Evaluations of anomalies found during General Condition Monitoring Activities determine whether analysis, repair, or further inspection is required. Occurrence of significant degradation that is adverse to quality is entered into the Corrective Action System. Corrective action provides reasonable assurance that conditions adverse to quality are promptly corrected.

18.2.10 Inspection Activities - Load Handling Cranes and Devices The load handling cranes within the scope of license renewal are listed below:

• Containment polar cranes

• Containment jib cranes

• Containment annulus monorails

• Refueling manipulator cranes

• Fuel handling bridge crane

• New fuel transfer elevator

• Spent fuel crane

• Auxiliary Building monorails The long-lived passive components of these cranes that are subject to aging management review include rails, towers, load trolley steel, fasteners, base plates, and anchorage. An internal inspection of representative sections of the box girders for the polar cranes will be implemented as a one-time only inspection. This inspection will be Page 12

Surry Power Station, Units 1 and 2 Application for Renewed Operating Licenses Revised UFSAR Supplement performed between year 30 and 40 of operation. An engineering evaluation will determine whether subsequent inspections are required.

The Inspection Activities - Load Handling Cranes and Devices has been developed in accordance with ASME B30.2 (Reference 13) and the inspection activities for monorails are developed in accordance with ASME B30.11 (Reference 14).

The Work Control Process directs structural integrity inspections of applicable cranes which include specific steps to check (visually inspect) the condition of structural members and fasteners on the cranes, the runways along which the cranes move, and the baseplates and anchorages for the runways. The applicable aging effect is identified as loss of material. If the nature of any identified discrepancies is such that corrective action can be completed within the scope of the procedure performing the inspection, no additional corrective action may be necessary. Corrective actions for conditions that are adverse to quality are performed in accordance with the Corrective Action System.

Corrective action provides reasonable assurance that conditions adverse to quality are promptly corrected.

18.2.11 ISl Program - Component and Component Support Inspections The ISI Program - Component and Component Support Inspections are performed in accordance with the requirements of Subsections IWB, IWC, and IWF of ASME XI, Rules for Inservice Inspection of Nuclear Power Plant Components. For this program, the license renewal concerns with respect to Subsection IWC include only the carbon steel piping that is susceptible to high energy line breaks in the feedwater and main steam systems. Inservice Inspection requirements may be modified by applicable Relief Requests and Code Cases, which are approved by the NRC specifically for each unit.

The scope and details of the inspections to be performed are contained in the individualized Inservice Inspection Plan for each unit. Each Inservice Inspection Plan is developed and approved by the NRC for a 120-month inspection interval. The examinations required by ASME Section XI utilize visual, surface, and volumetric inspections to detect loss of material, cracking, gross indications of loss of pre-load, and gross indications of reduction in fracture toughness (which presents itself as cracking of cast-austenitic stainless steel valve bodies due to thermal embrittlement).

Dominion actively participates in the EPRI-sponsored Materials Reliability Project Industry Task Group on thermal fatigue which currently is developing industry guidance for the management of fatigue caused by cyclic thermal stratification and environmental effects. Dominion is committed to following industry activities related to failure mechanisms for small-bore piping and will evaluate changes to inspection activities based on industry recommendations.

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Surry Power Station, Units 1 and 2 Application for Renewed Operating Licenses Revised UFSAR Supplement Acceptance standards for inservice inspections are identified in Subsection IWB for Class 1 components, Subsection IWC for included Class 2 components, and in Subsection IWF for component supports. Table IWB 2500-1 refers to acceptance standards listed in paragraph IWB 3500. Anomalous indications beyond the criteria set forth in the Code acceptance standards that are revealed by the inservice inspections of Class 1 components may require additional inspections of similar components in accordance with Section XI. Evidence of loss of material, cracking, and gross indications of either loss of pre-load or reduction of fracture toughness requires engineering evaluation for determination of corrective action. Occurrence of significant degradation that is adverse to quality will be entered into the Corrective Action System. Corrective action provides reasonable assurance that conditions adverse to quality are promptly corrected.

18.2.12 ISI Program - Containment Inspection The ISI Program - Containment Inspection for concrete containments and containment steel liners implements the requirements in 10 CFR 50.55a and Subsections IWE and IWL of ASME Section XI, 1992 edition through 1992 addenda. The program incorporates applicable code cases and approved relief requests. The provisions of 10 CFR 50.55a are invoked for inaccessible areas within the Containment structure.

Loss of material is the aging effect for the containment steel liner. Surface degradation and wall thinning are checked by visual and volumetric examinations. The frequency and scope of examination requirements are specified in 10 CFR 50.55a and Subsection IWE.

Loss of material, cracking and change in material properties are the aging effects for the containment concrete and are checked by visual examinations. The frequency and scope of examination requirements are specified in 10 CFR 50.55a and Subsections IWL.

These inspections provide reasonable assurance that aging effects associated with the containment liner and concrete are detected prior to compromising design basis requirements. The evaluations of accessible areas provide the basis for extrapolation to the expected condition of inaccessible areas, and an assessment of degradation in such areas.

During the course of containment inspections, anomalous indications are recorded on inspection reports that are kept in Station Records. Acceptance standards for the IWE inspections are identified in ASME Section XI Table IWE 2500-1 and refer to 10 CFR 50, Appendix J. For the IWL inspections, acceptance standards are identified in ASME Section XI Table IWL 2500-1. Engineering evaluations are performed for inspection results that do not meet established acceptance standards. Occurrence of significant degradation that is adverse to quality will be entered into the Corrective Action System.

Corrective action provides reasonable assurance that conditions adverse to quality are promptly corrected.

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Surry Power Station, Units 1 and 2 Application for Renewed Operating Licenses Revised UFSAR Supplement 18.2.13 ISI Program - Reactor Vessel The ISI Program - Reactor Vessel is performed in accordance with the requirements of Subsection IWB of ASME XI, Rules for Inservice Inspection of Nuclear Power Plant Components. Inservice Inspection requirements may be modified by applicable Relief Requests and Code Cases, which are approved by the NRC specifically for each unit.

The scope and details of the inspections to be performed are contained in the individualized Inservice Inspection Plan for each unit. Each Inservice Inspection Plan is developed and approved by the NRC for a 120-month inspection interval. Dominion will follow industry efforts (in addition to the existing reliance on chemistry control and ASME Section XI inspections) regarding inspection of core support lugs. Industry recommendations will be considered to determine the need for enhanced inspections.

In accordance with ASME Section XI, reactor vessel components are inspected using a combination of surface examinations, volumetric examinations, and visual examinations to detect the aging effects of loss of material, cracking, gross indications of loss of pre-load, and gross indications of reduction in fracture toughness. Acceptance standards for inservice inspections are identified in Subsection IWB for Class 1 components. Table IWB 2500-1 refers to acceptance standards listed in paragraph IWB 3500. Anomalous indications that are revealed by the inservice inspections may require additional inspections of similar components, in accordance with Section XI. Evidence of aging effects requires engineering evaluation for determination of corrective action. Occurrence of significant degradation that is adverse to quality is entered into the Corrective Action System. Corrective action provides reasonable assurance that conditions adverse to quality are promptly corrected.

18.2.14 Reactor Vessel Integrity Management The scope of the Reactor Vessel Integrity Management activities is focused on ensuring adequate fracture toughness of the reactor vessel beltline plate and weld materials.

Neutron dosimetry and material properties data derived from the reactor vessel materials irradiation surveillance program are used in calculations and evaluations that demonstrate compliance with applicable regulations. The Reactor Vessel Integrity Management activities includes the following aspects:

• Irradiated sample (capsule) surveillance.

• Vessel fast neutron fluence calculations.

• Measurements and calculations of nil-ductility transition temperature (RTNDT) for vessel beltline materials.

• Measurements and calculations of Charpy Upper Shelf Energy (CvUSE).

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Surry Power Station, Units 1 and 2 Application for Renewed Operating Licenses Revised UFSAR Supplement

"* Calculation of reactor coolant system pressure-/temperature (P-T operating limits, and Low Temperature Overpressure Protection System setpoints.

"* Pressurized Thermal Shock screening calculations.

Specimen capsules were placed in each of the reactors prior to initial irradiation and contain reactor vessel plate and weld material samples. The baseline mechanical properties of reactor vessel steels are determined from pre-irradiation testing of Charpy V-notch and tensile specimens. Post-irradiation testing of similar specimens provides a measure of radiation damage.

Fast neutron irradiation is the cause of radiation damage to the reactor vessel beltline.

The results of surveillance capsule dosimetry analyses are used as benchmarks for calculations of neutron fluence to the surveillance capsules and to the reactor vessel beltline.

Measured values of Charpy transition temperature and CvUSE are obtained from mechanical testing of irradiation surveillance program specimens. Measured values of transition temperature are used to determine the reference temperature for nil-ductility transition (RTNDT) for the limiting reactor vessel beltline material. RTNDT is a key analysis input for the determination of reactor coolant system pressure-temperature operating limits and LTOPS setpoints. Measured values of transition temperature shift are similarly utilized in PTS screening calculations required by 10 CFR 50.61. Measured values of CvUSE are used to verify compliance with the upper shelf energy requirements of 10 CFR 50 Appendix G.

Acceptable values are established for the following parameters:

"* Heatup and cooldown limits, as implemented by Technical Specifications, to ensure reactor vessel integrity.

"* A pressurized thermal shock reference temperature that is within the screening criteria of 10 CFR 50.61.

"* A fast fluence value for the surveillance capsule that bounds the expected fluence at the affected vessel beltline material through the period of extended operation.

• Charpy Upper Shelf Energy (CvUSE) greater than limits set forth in 10 CFR 50, Appendix G.

Based on established parameters, calculations are performed to ensure that the units will remain within the acceptable values.

18.2.15 Reactor Vessel Internals Inspection Visual inservice inspections are implemented in accordance with Category B-N-3 (Removable Core Support Structures) of ASME Section Xl, Subsection IWB, to determine the possible occurrence of age-related degradation. These inspections are performed at Page 16

Surry Power Station, Units 1 and 2 Application for Renewed Operating Licenses Revised UFSAR Supplement 10-year intervals in accordance with the inspection plans approved by the NRC. The scope of components that comprise the reactor internals includes the upper and lower core internals assemblies. This includes core support and hold-down spring components, as well as, the baffle/former bolting and barrel/former bolting. Additionally, a one-time focused inspection of the reactor vessel internals will be performed between year 30 and 40 of operation. The one-time inspection will look for indications of the presence of aging effects identified in the aging management review for the reactor vessel internals. The inspection will be performed on one reactor (at either Surry or North Anna) and an engineering evaluation of results will determine the need for inspections of the other units.

Dominion will remain active in industry groups, including the EPRI-sponsored Materials Reliability Project Industry Task Group, to stay aware of any new industry recommendations regarding such aging management issues as neutron embrittlement, void swelling, and the synergistic effect of thermal and neutron embrittlement of internals sub-components. If future industry developments suggest the need for an alternate inspection plan during the period of extended operation, or negate the need for a one-time inspection, then Dominion will modify the proposed inspection plan.

Visual inspections are utilized to detect loss of material and cracking; as well as, gross indications of loss of pre-load and/or reduced fracture toughness. The acceptance standards for the visual examinations are summarized in ASME Subsection IWB-3520.2, Visual Examination, VT-3. These inspections are directed to be performed with the internals assemblies removed from the reactor vessel.

Acceptance standards for Reactor Vessel Internals Inspection activities are identified in ASME Section XI, Subsection IWB. Table IWB 2500-1 identifies references to the acceptance standards listed in Paragraph IWB 3500. Anomalous indications, that are revealed to be beyond the criteria in the acceptance standards by the inservice inspections, may require additional inspections. Evidence of any component degradation requires engineering evaluation for determination of corrective action. Occurrence of significant degradation that is adverse to quality is entered into the Corrective Action System. Corrective action provides reasonable assurance that conditions adverse to quality are promptly corrected.

18.2.16 Secondary Piping and Component Inspection The purpose of the Secondary Piping and Component Inspection program is to identify, inspect, and trend components that are susceptible to the aging effect of loss of material as a result of Flow Accelerated Corrosion (FAC) in either single or two-phase flow conditions. This program has been implemented in accordance with NRC Generic Letter 89-08, Erosion/Corrosion-Induced Pipe Wall Thinning (Reference 15), and NUREG-1344, Erosion/Corrosion-Induced Pipe Wall Thinning in U.S. Nuclear Power Plants (Reference Page 17

Surry Power Station, Units 1 and 2 Application for Renewed Operating Licenses Revised UFSAR Supplement 16), and EPRI Guideline NSAC-202L, Recommendations for an Effective Flow Accelerated Corrosion Program (Reference 17).

The scope of the Secondary Piping and Component Inspection program includes portions of the feedwater systems, the main and auxiliary steam systems, and the steam generator blowdown lines.

The identification of components and piping segments to be included in each Secondary Piping and Component Inspection effort is performed by Engineering using plant chemistry data, past inspection data, predictions from FAC-monitoring computer codes, and industry experience. Determination of whether a piping component has experienced FAC degradation is made by measuring the current wall thickness using the UT method and comparing against previous baseline thickness measurement, if available. Visual inspections of the internals of non-piping components, such as pumps and valves, are performed as the equipment is opened for other repairs and/or maintenance, to determine whether flow-accelerated degradation is occurring.

The decision to repair or replace a component is made by Engineering. For the internal surface examinations, engineering evaluations are utilized to determine whether the results of visual inspections indicate conditions that require corrective action.

Occurrences of significant degradation that are adverse to quality are entered into the Corrective Action System. Corrective action provides reasonable assurance that conditions adverse to quality are promptly corrected.

18.2.17 Service Water System Inspections Compliance with Generic Letter 89-13 (Reference 18) requires a variety of inspections, non-destructive examinations, and heat transfer testing for components cooled by service water. Generic Letter 89-13 directed utilities to assess the following aspects of operational problems with service water cooling systems:

• Biofouling

• Heat Transfer Testing

• Routine Inspection and Maintenance

• Single-failure Walkdown

• Procedure Review The Service Water System Inspections program provides reasonable assurance that corrosion (including microbiologically-influenced corrosion, MIC), erosion, protective coating failure, silting, and biofouling of service water piping and components will not cause a loss of intended function. The primary objectives of this program are to (1) remove excessive accumulations of biofouling agents, corrosion products, and silt; and (2) repair defective protective coatings and degraded service water system piping and Page 18

Surry Power Station, Units 1 and 2 Application for Renewed Operating Licenses Revised UFSAR Supplement components that could adversely affect performance. Preventive maintenance, inspection, and repair procedures have been developed to provide reasonable assurance that any adverse effects of exposure to service water are adequately addressed. The addition of biocide to the service water system reduces biological growth (including MIC) that could lead to degradation of components exposed to the service water.

Service Water System Inspections are performed to check for biofouling, damaged coatings, and degraded material condition. Heat transfer parameters for components cooled by service water are monitored. Visual inspections are performed to check for loss of material and changes in material properties. Heat transfer testing is performed to identify the aging effects of loss of material and heat transfer degradation.

The acceptance criteria for visual inspections are identified in the procedures that perform the individual inspections. The procedures identify the type and degree of anomalous conditions that are signs of degradation. In the case of service water, degradation includes biofouling as well as material degradation. Engineering evaluations determine whether observed deterioration of material condition is sufficiently extensive to lead to loss of intended function for components exposed to the service water. The degraded condition of material or of heat transfer capability may require prompt remediation.

Occurrence of significant degradation that is adverse to quality is entered into the Corrective Action System. Corrective action provides reasonable assurance that conditions adverse to quality are promptly corrected.

18.2.18 Steam Generator Inspections Steam Generator Inspections are performed in accordance with Technical Specifications and Inservice Inspection requirements of ASME Section XI. Steam Generator Inspections plans are based upon the guidelines established by Nuclear Energy Institute document, NEI 97-06 (Reference 4) and the Electric Power Research Institute steam generator inspection guidelines (Reference 5). Steam generator tubing inspections are performed on a sampling basis. The sample population inspected meets or exceeds the requirements of Technical Specifications. Qualified techniques, equipment and personnel are used for inspections in accordance with site-specific eddy current analysis guidelines.

Examination of steam generator sub-components other than tubes are performed as required by the governing edition and addenda of ASME Section XI, as imposed by 10 CFR 50.55a. In some cases the specific inspection requirements of ASME Section XI are modified by regulatory commitments and approved Relief Requests. Inspections of the steam generators to check for loss of material, cracking, and gross indications of loss of pre-load include a combination of visual inspections, surface examinations, and volumetric examinations. Tubing inspections are performed in accordance with ASME Section XI, Subsection IWB.

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Surry Power Station, Units 1 and 2 Application for Renewed Operating Licenses Revised UFSAR Supplement Acceptance standards for steam generator inspections are provided in ASME Section XI, Subsections IWB-3500 and IWC-3500. Evidence of component degradation requires engineering evaluation for determination of corrective action. Occurrence of significant degradation that is adverse to quality will be entered into the Corrective Action System.

Corrective action provides reasonable assurance that conditions adverse to quality are promptly corrected.

18.2.19 Work Control Process Performance testing and maintenance activities, both preventive and corrective, are planned and conducted in accordance with the station's Work Control Process. The Work Control Process integrates and coordinates the combined efforts of Maintenance, Engineering, Operations, and other support organizations to manage maintenance and testing activities. Performance testing on heat exchangers evaluates the heat transfer capability of the components to determine if heat transfer degradation is occurring.

Maintenance activities provide opportunities for inspectors who are QMT or VT qualified to visually inspect the surfaces (internal and external) of plant components and adjacent piping. Adjacent piping is primarily the internal piping surfaces immediately adjacent to a system component that is accessible through the component for visual inspection. Visual inspections performed through the Work Control Process provide data that can be used to determine the effectiveness of the Chemistry Control Program for Primary Systems and Chemistry Control Program for Secondary Systems to mitigate the aging effects of cracking, loss of material, and change of material properties.

Changes to procedures to reasonably assure that consistent inspections of components are completed during the process of performing work activities (Work Control Process) will be implemented prior to the end of year 40 of operation.

The Work Control Process also provides opportunities through preventive maintenance sampling (predictive analysis) to collect lubricating oil and engine coolant samples for subsequent analysis of contaminants that would provide early indication of an adverse environment that can lead to material degradation.

The inspections, testing, and sampling performed under the Work Control Process provide reasonable assurance that the following aging effects will be detected:

• loss of material

• cracking

• heat transfer degradation

• separation and cracking/delamination

• change in material properties Page 20

Surry Power Station, Units 1 and 2 Application for Renewed Operating Licenses Revised UFSAR Supplement The acceptance criteria for visual inspections, testing, or sampling are currently identified in the procedures that perform the individual maintenance, testing, or sampling activity.

The procedures identify the type and degree of anomalous conditions that are signs of degradation.

Whenever evidence of aging effects exists, an engineering evaluation is performed to determine whether the observed condition is acceptable without repair. Occurrence of significant aging effects that is adverse to quality is entered into the Corrective Action System. If the evaluation of an anomalous condition indicates that the occurrence was unexpected for the operational conditions involved, the Work Control Process will be used to ensure that locations with similar material and environmental conditions will be inspected.

As confirmation that the Work Control Process has inspected representative components from each component group for which the Work Control Process is credited to manage the effects of aging, periodic audits of inspections actually performed will be performed and, if Work Control Process activities are found not to be representative, supplemental inspections will be performed. Two audits of the Work Control Process are anticipated, and each will consist of a review of the previous 10 years of historical data. One audit will be performed prior to 40 years of plant operation, and another will be performed at approximately 50 years of plant operation. Any required supplemental inspections would be completed within 5 years after the audits are performed.

18.2.20 Corrective Action System The Corrective Action System is a required element of the Quality Assurance Program outlined in the Quality Assurance Topical Report (Chapter 17 of the Updated Final Safety Analysis Report). The Quality Assurance Program implements the requirements of 10 CFR 50, Appendix B, and is consistent with the summary in Section A.2 of NUREG-1 800, Standard Review Plan for License Renewal. The Corrective Action System activities include 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.

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Surry Power Station, Units 1 and 2 Application for Renewed Operating Licenses Revised UFSAR Supplement 18.3 Time-Limited Aging Analysis As part of the application for a renewed license, 10 CFR 54.21(c) requires that an evaluation of time-limited aging analyses (TLAAs) for the period of extended operation be provided. The following TLAAs have been identified and evaluated to meet this requirement.

18.3.1 Reactor Vessel Neutron Embrittlement The reactor vessel is subjected to neutron irradiation from the core. This irradiation results in the embrittlement of the reactor vessel materials. Analyses have been performed that address the following:

• Upper shelf energy

• Pressurized thermal shock

• RCS pressure-temperature operating limits 18.3.1.1 Upper Shelf Energy The Charpy V-notch test provides information about the fracture toughness of reactor vessel materials. 10 CFR 50 requires the Charpy upper shelf energy (CvUSE) of reactor vessel beltline materials to meet Appendix G requirements. If the USE of a reactor vessel beltline material is predicted to not meet Appendix G requirements, then licensees must submit an analysis that demonstrates an equivalent margin of safety at least three years prior to the time the material is predicted to not meet those requirements.

Reactor vessel calculations have been performed which demonstrated that the upper shelf energy values of limiting reactor vessel beltline materials at the end of the period of extended operation meet Appendix G requirements. Thus, the TLAA has been projected to the end of the period of extended operation and is found to be adequate.

18.3.1.2 Pressurized Thermal Shock A limiting condition on reactor vessel integrity, known as pressurized thermal shock (PTS), may occur during postulated system transients, such as a loss-of-coolant accident (LOCA) or a steam line break. Such transients may challenge the integrity of the reactor vessel under the following conditions: severe overcooling of the inside surface of the vessel wall followed by high re-pressurization, significant degradation of vessel material toughness caused by radiation embrittlement, and the presence of a critical-size defect in the vessel wall.

The reference temperature for pressurized thermal shock (RTPTS) is defined in 10 CFR 50.61. RTPTS values for the limiting reactor vessel materials at the end of the period of extended operation have been recalculated by Dominion. At the end of the period of extended operation, the calculated RTPTS values for the beltline materials are less than Page 22

Surry Power Station, Units 1 and 2 Application for Renewed Operating Licenses Revised UFSAR Supplement the applicable screening criteria established in 10 CFR 50.61. Thus, the TLAA has been projected to the end of the period of extended operation and is found to be adequate.

18.3.1.3 Pressure-Temperature Limits Atomic Energy Commission (AEC) General Design Criterion (GDC) 14 of Appendix A of 10 CFR 50, "Reactor Coolant Pressure Boundary," requires that the reactor coolant pressure boundary be designed, fabricated, erected, and tested to have an extremely low probability of abnormal leakage (or rapid failure) and of gross rupture. AEC GDC 31, "Fracture Prevention of Reactor Coolant Pressure Boundary," requires that the reactor coolant pressure boundary be designed with sufficient margin to ensure that when stressed under operating, maintenance, and testing conditions the boundary behaves in a non-brittle manner and the probability of rapidly propagating fracture is minimized.

Reactor vessel neutron fluence values corresponding to the end of the period of extended operation and reactor vessel beltline material properties were used to determine the limiting value of reference nil ductility reference temperature (RTNDT), and to calculate RCS pressure-temperature (P-T) operating limits valid through the end of a period of extended operation. Maximum allowable low temperature overpressure protection system (LTOPS) power operated relief valve (PORV) lift setpoints have been developed on the basis of the P-T limits applicable to the period of extended operation. Revised RCS P-T limit curves and LTOPS setpoints will be submitted for review and approval prior to the expiration of the existing technical specification limits in order to maintain compliance with the governing requirements of 10 CFR 50 Appendix G.

The TLAA has been projected to the end of the period of extended operation and is found to be adequate.

18.3.2 Metal Fatigue The thermal fatigue analyses of the station's mechanical components have been identified as time-limited aging analyses.

18.3.2.1 ASME Boiler and Pressure Vessel Code,Section III, Class 1 The steam generators, pressurizers, reactor vessels, reactor coolant pumps, control rod drive mechanisms (CRDMs), and pressurizer surge line piping have been analyzed using the methodology of the ASME Boiler and Pressure Vessel Code,Section III, Class 1.

The ASME Boiler and Pressure Vessel Code,Section III, Class 1, requires a design analysis to address fatigue and establish limits such that the initiation of fatigue cracks is precluded.

Experience has shown that the transients used to analyze the ASME III requirements are often very conservative. Design transient magnitude and frequency are more severe than Page 23

Surry Power Station, Units 1 and 2 Application for Renewed Operating Licenses Revised UFSAR Supplement those occurring during plant operation. The magnitude and number of the actual transients are monitored. This monitoring assures that the existing frequency and magnitude of transients are conservative and bounding for the period of extended operation, and that the existing ASME III equipment will perform its intended functions for the period of extended operation. A cycle counting program (Section 18.4.2) is in place to provide reasonable assurance that the actual transients are smaller in magnitude and within number of the transients used in the design.

Fatigue analyses for the steam generators, pressurizers, reactor vessels, reactor coolant pumps, CRDMs, and pressurizer surge lines have been evaluated and determined to remain valid for the period of extended operation.

Fatigue analyses for the reactor vessel closure studs have been re-analyzed. The analyses for these components have been projected to be valid for the period of extended operation.

18.3.2.2 Reactor Vessel Underclad Cracking In early 1971, an anomaly was identified in the heat-affected zone of the base metal in a European-manufactured reactor vessel. A generic fracture mechanics evaluation by Westinghouse demonstrated that the growth of underclad cracks during a 40-year plant life would be insignificant.

The evaluation was extended to 60 years using fracture mechanics evaluation based on a representative set of design transients. The occurrences were extrapolated to cover 60 years of service life. This 60-year evaluation shows insignificant growth of the underclad cracks and is documented in WCAP-15338 (Reference 21). The plant-specific design transients are bounded by the representative set used in the evaluation.

The analysis associated with reactor vessel underclad crack growth has been projected to the end of the period of extended operation and has been found to be acceptable.

18.3.2.3 ANSI B31.1 Piping The balance-of-plant piping and reactor coolant pressure boundary piping except the pressurizer surge line piping are designed to the requirements of ANSI B31.1, "Power Piping."

ANSI B31.1 design requirements assume a stress range reduction factor in order to provide conservatism in the piping design while accounting for fatigue due to thermal cyclic operation. This reduction factor is 1.0, provided the number of anticipated cycles is limited to 7,000 equivalent full-temperature cycles. A piping system would have to be thermally cycled approximately once every three days over a plant life of 60 years to reach 7,000 cycles. Considering this limitation, a review of the ANSI B31.1 piping within Page 24

Surry Power Station, Units 1 and 2 Application for Renewed Operating Licenses Revised UFSAR Supplement the scope of license renewal has been performed to identify those systems that operate at elevated temperature and to establish their cyclic operating practices. Under current plant operating practices, piping systems within the scope of license renewal are only occasionally subject to cyclic operation. Typically, these systems are subjected to continuous steady-state operation. Significant variation in operating temperatures occur only during plant heatup and cooldown, during plant transients, or during periodic testing.

The analyses associated with ANSI B31.1 piping fatigue have been evaluated and determined to remain valid for the period of extended operation.

18.3.2.4 Environmentally Assisted Fatigue Generic Safety Issue (GSI)-190 (Reference 6) identifies a NRC staff concern about the effects of reactor water environments on reactor coolant system component fatigue life during the period of extended operation. The reactor water's environmental effects as described in GSI-1 90, are not included in the current licensing basis. As a result, the criterion specified in 10 CFR 54.3(a)(6) is not satisfied. Hence, environmental effects are not TLAAs. GSI-1 90, which was closed in December 1999, has concluded that environmental effects have a negligible impact on core damage frequency, and as such, no generic regulatory action is required (Reference 7). However, as part of the closure of GSI-1 90, the NRC has concluded that licensees who apply for license renewal should address the effects of coolant environment on component fatigue life as part of their aging management programs. As demonstrated in the preceding sections, fatigue evaluation in the original transient design limits remain valid for the period of extended operation.

Confirmation by transient cycle counting will ensure that these transient design limits are not exceeded. Secondly, the reactor water's environmental effects on fatigue life were evaluated using the most recent data from laboratory simulation of the reactor coolant environment.

As a part of the industry effort to address environmental effects for operating nuclear power plants during the current 40-year licensing term, Idaho National Engineering Laboratories evaluated, in NUREG/CR-6260, "Application of NUREG/CR-5999 Interim Fatigue Curves to Selected Nuclear Power Plant Components" (Reference 8),

fatigue-sensitive component locations at plants designed by all four U. S. Nuclear Steam Supply System vendors. The pressurized water reactor calculations, especially the early-vintage Westinghouse PWR calculations, are directly relevant to the Dominion stations. The description of the "Older Vintage Westinghouse Plant" evaluated in NUREG/CR-6260 applies to the Surry station. In addition, the transient cycles considered in the evaluation match or bound the design. The results of NUREG/CR-6260 analyses, and additional data from NUREG/CR-6583 (Reference 9) and NUREG/CR-5704 (Reference 10), were then utilized to scale up the plant-specific cumulative usage factors Page 25

Surry Power Station, Units 1 and 2 Application for Renewed Operating Licenses Revised UFSAR Supplement (CUF) for the fatigue-sensitive locations to account for environmental effects. Generic industry studies performed by EPRI were also considered in this aspect of the evaluation, as well as environmental data that have been collected and published subsequent to the generic industry studies.

Based on these adjusted CUFs, it has been determined that the surge line connection at the reactor coolant system's hot leg pipe is the leading indicator for reactor water environmental effects. Therefore, the surge line weld at the hot leg pipe connection will be included in an Augmented Inspection Activities (Section 18.2.1).

The potential effects of the reactor water environment have been evaluated for the period of extended operation as required by GSI-1 90.

18.3.3 Environmental Qualification of Electric Equipment 10 CFR 54.49 requires that each holder of a nuclear power plant operating license establish a program for qualifying safety-related electric equipment. Such a program has been implemented at the station and is invoked by Administrative Procedure. Analyses and tests that qualify safety-related equipment for the period of extended operation are considered TLAAs.

The Environmental Qualification Program (Section 18.4.1) requires that all electrical equipment important to safety located in a harsh environment shall be managed through the period of extended operation.

18.3.4 Containment Liner Plate The accumulated fatigue effects of applicable liner loading conditions were evaluated in accordance with Paragraph N-415 of the ASME Boiler and Pressure Vessel Code,Section III, 1968. The evaluation was based on 1,000 cycles of operating pressure variations, 4,000 cycles of operating temperature variations, and 20 design earthquake cycles. The operating pressure variations are anticipated to be less than 100 and temperature variations are anticipated to be less than 400 for forty years of operation.

Extrapolating these anticipated values for sixty years of operation results in 150 pressure variations and 600 temperature variations (Section 15.5.1.8). The number of design cycles was conservatively increased to 1,500 cycles of operating pressure variations, 6,000 cycles of operating temperature variation, and 30 design earthquake cycles by using a multiplication factor of 1.5, to account for the period of extended operation.

A review of the identified calculations has determined that the increase in the number of cycles due to the period of extended operation is acceptable. Effects of the Containment Type A pressure tests on fatigue of the Containment liner plate have been included in the evaluation. Therefore, the Containment liner is adequate for a 60-year operating period Page 26

Surry Power Station, Units 1 and 2 Application for Renewed Operating Licenses Revised UFSAR Supplement as currently designed. The analyses associated with the Containment liner plate have been revised and projected to be valid for the period of extended operation.

18.3.5 Plant-Specific Time-Limited Aging Analyses 18.3.5.1 Crane Load Cycle Limit The following are cranes included in license renewal scope and in NUREG-0612 (Reference 11):

• Containment polar cranes

• Containment annulus monorails

• Fuel handling bridge crane

• Spent fuel crane

• Auxiliary Building monorails

• Containment jib cranes NUREG-0612 requires that the design of heavy load overhead handling systems meet the intent of Crane Manufacturers Association of America, Inc. (CMAA) Specification #70.

The crane load cycle provided in CMAA-70 has been identified as a TLAA, with the most limiting number of loading cycles being 100,000.

The most frequently used cranes are spent fuel cranes. Each of these cranes will experience approximately 25,000 cycles of half-load lifts to support the refueling of both units over a 60-year period. In addition, the crane is used to load new fuel into the fuel pool, to perform the various rearrangements required by operations support, to accommodate inspections by fuel vendors, and to load spent fuel casks. In such service, the crane is conservatively expected to make a total of 50,000 half-load lifts in a 60-year period.

Therefore, the analyses associated with crane design, including fatigue, are valid for the period of extended operation.

18.3.5.2 Reactor Coolant Pump Flywheel During normal operation, the reactor coolant pump flywheel possesses sufficient kinetic energy to produce high-energy missiles in the unlikely event of failure.

The aging effect of concern is fatigue crack initiation in the flywheel bore keyway. An evaluation of a failure over the period of extended operation has been performed. It demonstrates that the flywheel design has a high structural reliability with a very high flaw tolerance and negligible flaw crack growth over a 60-year service life (Reference 12).

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Surry Power Station, Units 1 and 2 Application for Renewed Operating Licenses Revised UFSAR Supplement The analysis associated with the structural integrity of the reactor coolant pump flywheel has been evaluated and determined to be valid for the period of extended operation.

18.3.5.3 Leak-Before-Break Westinghouse (Westinghouse Owners Group) tested and analyzed crack growth with the goal of eliminating reactor coolant system primary loop pipe breaks from plant design bases. The objective of the investigation was to examine mechanistically, under realistic yet conservative assumptions - whether a postulated crack causing a leak, will grow to become unstable and lead to a full circumferential break when subjected to the worst possible combinations of plant loading.

The detailed evaluation has shown that double-ended breaks of reactor coolant pipes are not credible, and as a result, large LOCA loads on primary system components will not occur. The overall conclusion of the evaluation was, that, under the worst combination of loading, including the effects of safe shutdown earthquake, the crack will not propagate around the circumference and cause a guillotine break. The plant has leakage detection systems that can identify a leak with margin, and provide adequate warning before the crack can grow.

The concept of eliminating piping breaks in reactor coolant system primary loop piping has been termed "leak-before-break" (LBB).

Fatigue crack growth has been identified as an LBB TLAA. The fatigue crack growth analysis has been performed using RCS design transient cycles. The original analysis, however, did not consider the effects of the thermal aging of cast austenitic stainless steel (CASS).

To maintain the plant's LBB design basis, the thermal aging effect for 60 years has been revalidated. The change in the material property has been found to be insignificant. Since the number of design transient cycles will not be exceeded during 60 years of operation, the LBB analysis is projected to be valid for the period of extended operation.

18.3.5.4 Spent Fuel Pool Liner The spent fuel pool liner located in the Fuel Building is needed to prevent a leak to the environment. A design calculation has been identified which documents that the spent fuel pool design meets the general industry criteria. The calculation includes a fatigue analysis to add a further degree of confidence.

The normal thermal cycles occur at each refueling, resulting in 80 cycles for both units in 60 years. Total number of thermal cycles is expected to be 90, which includes normal, upset, emergency, and faulted conditions.

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Surry Power Station, Units 1 and 2 Application for Renewed Operating Licenses Revised UFSAR Supplement The calculations show that the allowable thermal cycles for spent fuel pool liner for the most severe thermal condition, which includes a loss of cooling, is 95.

Therefore, the existing calculations remain valid for the period of extended operation.

18.3.5.5 Piping Subsurface Indications Calculations have been identified that addressed piping subsurface indications detected by inspections, performed in accordance with ASME Section XI. Section XI provides the acceptance criteria for various flaw orientations, locations and sizes. The calculations determined the number of thermal cycles required for the flaws to reach unacceptable size.

Required cycles for the flaws to reach an unacceptable size are 37,500 or higher.

Since it is expected that the number of the cycles experienced by the piping will not exceed these values for sixty years of operation, the analyses have been determined to remain valid for the period of extended operation.

18.3.5.6 Reactor Coolant Pump and ASME Code Case N-481 Periodic volumetric inspections of the welds in the primary loop pump casings in commercial nuclear power plants are required by Section XI of the ASME Boiler and Pressure Vessel Code. Since the reactor coolant pump casings are inspected prior to being placed in service, and no significant mechanisms exist for crack initiation and propagation; it has been concluded that the inservice volumetric inspection could be replaced with an acceptable alternate inspection. In recognition of this conclusion, ASME Code Case N-481, "Alternative Examination Requirements for Cast Austenitic Pump Casings," provides an alternative to the volumetric inspection requirement. The code case allows the replacement of volumetric examinations of primary loop pump casings with fracture mechanics based integrity evaluations - Item (d) of the code case - supplemented by specific visual examinations. The analysis has been performed on the reactor coolant pump casing integrity in accordance with the ASME Code Case N-481 requirements. The analysis has been projected to be valid for 60 years.

18.3.6 Exemptions The requirements of 10 CFR 54.21 (c) stipulate that the application for a renewed license should include a list of plant-specific exemptions granted pursuant to 10 CFR 50.12 and that are based on time-limited aging analyses, as defined in 10 CFR 54.3. Each active 10 CFR 50.12 exemption has been reviewed to determine whether the exemption is based on a time-limited aging analysis. No plant-specific exemptions granted pursuant to 10 CFR 50.12 and based on a time-limited aging analysis as defined in 10 CFR 54.3 have been identified.

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Surry Power Station, Units 1 and 2 Application for Renewed Operating Licenses Revised UFSAR Supplement 18.4 TLAA Supporting Activities 18.4.1 Environmental Qualification Program The Environmental Qualification (EQ) Program activities are in compliance with the requirements of 10 CFR 50.49. The EQ Program will be continued throughout the period of extended operation. Electrical equipment located in a harsh environment is evaluated for environmental qualification if they are required to function in the conditions that will exist post-accident after being subjected to the normal effects of aging. A harsh environment results from a loss-of-coolant accident (LOCA) or main steam line break inside Containment, high radiation levels due to the post-LOCA effects outside Containment, or high energy line breaks outside Containment.

The EQ Program is applicable to the following groups of components:

"* Safety-related electrical equipment that is relied upon to remain functional during and following a design-basis event (DBE)

"* Non-safety-related electrical equipment whose failure, under postulated environmental conditions, could prevent accomplishment of safety functions

"* Certain post-accident monitoring equipment as described in Regulatory Guide 1.97 (Reference 19).

Guidance regarding environmental qualification was given in NRC Bulletin 79-01B (Reference 20).

The Equipment Qualification Master List (EQML) provides a listing of electrical equipment that is important to safety and is located in a potentially harsh environment.

Based on the definitions of 10 CFR 54, certain EQ calculations are considered to be Time-Limited Aging Analyses (TLAA). As stated in 10 CFR 54.21(c) and in NEI 95-10 (Reference 22), analyses for TLAAs utilize one of the following three options:

i) The analyses remain valid for the period of extended operation, ii) The analyses have been projected to the end of extended operation, or iii)The effects of aging will be adequately managed during the period of extended operation.

For purposes of license renewal, EQ components will be evaluated utilizing Option iii in accordance with the EQ Program. EQ concerns for license renewal will consider only those in-scope components that have a qualified lifetime greater than 40 years. Components with a qualified lifetime of less than 40 years already are included in a program of periodic replacement and are not considered TLAAs.

10 CFR 50.49(j) requires that a qualification record be maintained for all equipment covered by the EQ Rule. The qualification process verifies that the equipment is capable of Page 30

Surry Power Station, Units 1 and 2 Application for Renewed Operating Licenses Revised UFSAR Supplement performing its safety function when subjected to various postulated environmental conditions. These conditions include expected ranges of temperature, pressure, humidity, radiation, and accident conditions such as chemical spray and submergence.

The process of qualifying EQ equipment includes analysis, data collection, and data reduction with appropriate assumptions, acceptance criteria and corrective actions.

Qualification Document Reviews (QDRs) provide the basis for qualifying EQ components.

The QDRs provide the following information for each piece of equipment that is qualified:

"* The performance characteristics required under normal, design-basis event (DBE), and post-DBE conditions.

"* The voltage, frequency, load, and other electrical characteristics for which equipment performance can be provided with reasonable assurance.

"* The environmental conditions, including temperature, pressure, humidity, radiation, chemical spray, and submergence, at the location where the equipment must function.

18.4.2 Transient Cycle Counting During normal, upset, and test conditions; reactor coolant system pressure boundary components are subjected to transient temperatures, pressures, and flows, resulting in cyclic changes in internal stresses in the equipment. The cyclic changes in internal stresses cause metal fatigue. Class 1 reactor coolant system components have been designed to withstand a number of design transients without experiencing fatigue failures during their operating life. The purpose of the Transient Cycle Counting is to record the number of normal, upset, and test events, and their sequence that the station experiences during operation. Design transients are counted to provide reasonable assurance that plant operation does not occur outside the design assumptions.

The Transient Cycle Counting activities are applicable to the reactor coolant system pressure boundary components for which the design analysis assumes a specific number of design transients. A summary of reactor coolant system design transients for which transient cycle counting is performed is listed below:

"* Heatups/Cooldowns <100OF/Hr.

"* Step load increase/decrease of 10%

"* Large load reduction of 50%

"* Loss of load >15%

"* Loss of AC power

"* Loss of flow in one loop

"* Full power reactor trip

"* Inadvertent auxiliary pressurizer spray Page 31

Surry Power Station, Units 1 and 2 Application for Renewed Operating Licenses Revised UFSAR Supplement The aging effect that is managed by counting transient cycles is cracking due to metal fatigue. The Transient Cycle Counting activities monitor transient cycles that have been experienced by each unit and compare the actual number of cycles to a design assumption.

Any concerns related to fatigue are mitigated, as long as the number and magnitude of transient cycles are less than the design assumptions. Approaching a design limit may indicate a situation that is adverse to quality, and would initiate the Corrective Action System. Subsequently, an engineering analysis will determine the design margin remaining, taking credit for the actual magnitude of transients and their sequence to confirm that the allowable factor has not been exceeded.

If warranted, component repair or replacement would be initiated.

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Surry Power Station, Units 1 and 2 Application for Renewed Operating Licenses Revised UFSAR Supplement 18.5 References

1.

Working Draft of the NRC Standard Review Plan for the Review of License Renewal Applications for Nuclear Power Plants.

2.

Generic Letter 88-05, Boric Acid Corrosion of Carbon Steel Reactor Pressure Boundary Components in PWR Plants, March 17, 1988.

3.

NUREG-0800, Standard Review Plan for the Review of Safety Analysis Reports for Nuclear Power Plants - LWR Edition, US Nuclear Regulatory Commission. (Formerly NUREG-75/087)

4.

NEI 97-06, Steam Generator Program Guidelines, Revision 1, Nuclear Energy Institute.

5.

Power Steam Generator Examination Guidelines, TR-107569, Electric Power Research Institute.

6.

Generic Safety Issue (GSI)-1 90, Fatigue Evaluation for Metal Components for 60-year Plant Life, U.S. Nuclear Regulatory Commission, August 1996.

7.

Memorandum from Ashok C. Thadani, to William D. Travers, U.S. Nuclear Regulatory Commission, Closeout of Generic Safety Issue 190, December 26, 1999.

8.

NUREG/CR-6260, Application of NUREG/CR-5999 Interim Fatigue Curves to Selected Nuclear Power Plant Components, U.S. Nuclear Regulatory Commission, March 1995.

9.

NUREG/CR-6583, Effects of LWR Coolant Environments on Fatigue Design Curves of Carbon and Low-Alloy Steels, U.S. Nuclear Regulatory Commission, March 1998.

10. NUREG/CR-5704, Effects of LWR Coolant Environments on Fatigue Design Curves of Austenitic Stainless Steels, U.S. Nuclear Regulatory Commission, April 1999.

11.

NUREG-0612, Control of Heavy Loads at Nuclear Power Plants, U.S. Nuclear Regulatory Commission, July 1980.

12. WCAP-1 4535A, Topical Report On Reactor Coolant Pump Flywheel Inspection Elimination, Westinghouse Electric Corporation, November 1996.

13. American National Standards Institute: ANSI B30.2-1976, Overhead and Gantry Cranes.

14. American National Standards Institute: ANSI B30.11-1973, Monorail Systems and Underhung Cranes.

15. Generic Letter 89-08, Erosion/Corrosion-Induced Pipe Wall Thinning, May 2, 1989.

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Surry Power Station, Units 1 and 2 Application for Renewed Operating Licenses Revised UFSAR Supplement

16. NUREG-1344, Erosion/Corrosion-Induced Pipe Wall Thinning in US Nuclear Power Plants, April 1, 1989.

17. NSAC-202L, Recommendation for an Effective Flow Accelerated Corrosion Program, Electric power Research Institute, April 8, 1999.

18. Generic Letter 89-13, Service Water System Problems Affecting Safety-Related Equipment, July 18, 1989 (Supplement 1 dated 4/4/90).

19. U.S. Nuclear Regulatory Commission, Instrumentation for Light-Water-Cooled Nuclear Power Plants to Assess Plant and Environs Conditions During and Following an Accident, Regulatory Guide 1.97, December 1980.

20.

IE Bulletin 79-01 B, Environmental Qualification of Class 1E Equipment, Office of Inspection and Enforcement, January 14, 1980 (Supplement 1 dated 2/29/80; Supplement 2 dated 9/30/80; and Supplement 3 dated 10/24/80).

21.

WCAP-1 5338, A Review of Cracking Associated with Weld Deposited Cladding in Operating PWR Plants, Westinghouse Electric Corporation, March 2000.

22. NEI 95-10, Industry Guidance for Implementing the Requirements of 10 CFR Part 54 - The License Renewal Rule, Revision 2, August 2000.

Page 34

Docket Nos. 50-280/281 50-338/339 Serial No.: 02-360 Page 1 of 34 License Renewal - Revised North Anna UFSAR Supplement Serial No.02-360 North Anna Power Station, Units 1 and 2 License Renewal Virginia Electric and Power Company (Dominion)

Page 1

North Anna Power Station, Units 1 and 2 Application for Renewed Operating Licenses Revised UFSAR Supplement CHAPTER 18 18.0 PROGRAMS AND ACTIVITIES THAT MANAGE THE EFFECTS OF AGING The integrated plant assessment for license renewal identified new and existing aging management programs necessary to provide reasonable assurance that components within the scope of license renewal will continue to perform their intended functions consistent with the current licensing basis (CLB) for the period of extended operation. This chapter describes these programs and their planned implementation.

This chapter also discusses the evaluation results for each of the plant-specific time-limited aging analyses (TLAA's) performed for license renewal. The evaluations have demonstrated that the analyses remain valid for the period of extended operation; the analyses have been projected to the end of the period of extended operation; or that the effects of aging on the intended function(s) will be adequately managed for the period of extended operation.

18.1 New Aging Management Activities 18.1.1 Buried Piping and Valve Inspection Activities Prior to the period of extended operation, buried piping and valves will be inspected for the existence of aging effects. The Buried Piping and Valve Inspection Activities will include a one-time inspection of representative samples of piping and valves for different combinations of buried material and burial condition. Visual inspections will be used to detect cracking of protective coatings and loss of material from protective coatings or the substrate material.

The inspection will be completed between year 30 and 40 of operation and will include representative valves and sample lengths (i.e., several feet) of piping for each of the following combinations of material and burial conditions:

• Carbon steel, concrete encased

• Carbon steel, coated

• Carbon steel, coated, wrapped

• Carbon steel, coated, and wrapped with cathodic protection

• Stainless steel, coated, and wrapped An engineering evaluation of the results of the buried piping and valves inspections will be performed to determine future actions. Corrective actions for conditions that are adverse to quality are performed in accordance with the Corrective Action System. Corrective action provides reasonable assurance that conditions adverse to quality are promptly corrected.

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North Anna Power Station, Units 1 and 2 Application for Renewed Operating Licenses Revised UFSAR Supplement 18.1.2 Infrequently Accessed Area Inspection Activities The purpose of the Infrequently Accessed Area Inspection Activities is to provide reasonable assurance that equipment and components within the scope of License Renewal, which are not readily accessible, will continue to fulfill their intended functions during the period of extended operation. A one-time inspection will be performed between year 30 and 40 of operation to assess the aging of components and structures located in areas not routinely accessed due to high-radiation, high-temperature, confined spaces, location behind security or missile barriers, or normally flooded. The external condition of structures, supports, piping, and equipment will be determined by visual inspection.

These inspections would detect the aging effect of loss of material. In addition, concrete will be inspected to detect the aging effects of loss of material, cracking, and change in material properties.

Infrequently accessed areas determined to be within the scope of license renewal and the focus of inspections within these area include:

• Reactor containment - Sump areas, cabling and supports*

• Reactor containment keyway - Leakage, structural support provided by the neutron shield tank.

• Subsurface drains - Access shaft and component supports

• Cover for Containment dome plug - Structural condition

• Volume control tank (VCT) cubicle - Structure, supports, and equipment.

• Emergency diesel generator (EDG) exhaust bunkers - Structural condition

• Cable spreading rooms, Cable tunnels, Upper areas of emergency switchgear rooms Cable raceways and supports*

• New fuel storage area - Supports and structure affecting spent fuel pool cooling*

• Auxiliary Building filter and ion exchanger cubicles - Structure, supports, and equipment*

• Tunnel from Turbine Building to Auxiliary Building - Structure, supports, and piping*

• Service water (SW) expansion joint vault - Supports and piping

• SW tie-in vault - Supports and piping

• Auxiliary SW valve pit - Supports and piping

• Turbine building SW valve pit - Structures, supports and piping

• SW valve house lower level - Supports, piping, and equipment

• SW pump house lower level - Supports, piping, and equipment

• Spray array structure in SW reservoir - Underwater supports*

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North Anna Power Station, Units 1 and 2 Application for Renewed Operating Licenses Revised UFSAR Supplement

• Auxiliary SW expansion joint vault - Supports and piping*

• Charging pump pipe chase - Structure, supports and piping*

• Auxiliary feedwater piping tunnel - Structure, supports and piping*

Note: Representative samples will be inspected in areas denoted with an asterisk.

Inspection results will be documented for evaluation and retention. Engineering evaluation assesses the severity of the visual inspection results and determines the extent of required actions or future inspections. Corrective actions for conditions that are adverse to quality are performed in accordance with the Corrective Action System.

Corrective action provides reasonable assurance that conditions adverse to quality are promptly corrected.

18.1.3 Tank Inspection Activities The purpose of the Tank Inspection Activities is to perform inspections of above ground and underground tanks to provide reasonable assurance that the tanks will perform their intended function through the period of extended operation.

A one-time inspection will be performed between year 30 and 40 of operation for specified tanks that are within the scope of license renewal and could experience aging effects. The aging effect of concern for tanks is loss of material. A representative sample of tanks will be designated for the one-time inspections in order to assess the condition of tanks that require aging management. The choice of representative tanks to be inspected is dependent on the material of construction for the tank, its contents, the foundation upon which the tank is based, and the type of coating. Visual inspections of internal and external surfaces will be performed. Volumetric examinations will be performed to look for indications of wall thinning on tanks that are founded on soil or buried. Indications of degradation will be referred for evaluation by engineering.

The following tanks will be inspected or represented by suitable replacement samples:

• Emergency diesel generator tanks (fuel oil, coolant, and starting air)

• AAC diesel generator tanks (fuel oil, coolant and starting air)

• Security diesel generator tank (fuel oil)

• Underground fuel oil storage tanks

• Diesel-driven fire pump fuel oil storage tanks

• Refueling water storage tanks

• Chemical addition tanks

• Emergency condensate storage tanks Page 4

North Anna Power Station, Units 1 and 2 Application for Renewed Operating Licenses Revised UFSAR Supplement

• Casing cooling tanks

• Service water pump house air receiver An engineering evaluation may determine that the observed condition is acceptable or requires repair; or, in the case of degraded coatings, may direct removal of the coating, non-destructive examination of the substrate material, and replacement of the coating.

Re-inspections will be dependent upon the observed surface condition, and the results of this engineering evaluation. Corrective actions for conditions that are adverse to quality are performed in accordance with the Corrective Action System. Corrective action provides reasonable assurance that conditions adverse to quality are promptly corrected.

18.1.4 Non-EQ Cable Monitoring The purpose of the Non-EQ Cable Monitoring activities will be to perform inspections on a limited, but representative, number or accessible cable jackets and connector coverings that are utilized in non-EQ applications. In order to confirm that ambient conditions are not changing sufficiently to lead to age-related degradation of the in-scope cable jackets and connector coverings, initial visual inspections for the non-EQ application insulated power cables, instrumentation cables, and control cables (including low-voltge instrumentation and control cables that are sensitive to a reduction in insulation resistance) will be performed between year 30 and 40 of operation. Visual inspection of the representative samples of non-EQ power, instrumentation, and control cable jackets and connector coverings will detect the presence of cracking, discoloration, or bulging, which could indicate aging effects requiring management. These effects could be due to high radiation, high temperature, or wetted condition environments. Subsequent inspections to confirm ambient conditions will be performed at least once per 10 years following the initial inspection.

The potentially adverse localized environment due to moisture which could lead to water-treeing in high-or medium-voltage cables that are within the scope of license renewal, is also detected by visually monitoring for the presence of water around cables.

Programs utilizing periodic inspections and design features such as drains or sump pumps are used to control the cable localized environment. Cable found to be wetted for any significant period of time will be tested using an appropriate test method which has been proven to accurately assess the cable condition with regards to water treeing.

The source, intermediate, and power range neutron detector operate with high-voltage power supply in conjunction with low-voltage signal cables. The routine calibration of these detectors will be used to identify the potential existance of aging degradation in the associated cables.

Any anomalies resulting from the inspections will be dispositioned by Engineering and will consider the cable environment including the potential for moisture in the areas of the Page 5

North Anna Power Station, Units 1 and 2 Application for Renewed Operating Licenses Revised UFSAR Supplement anomolies. Occurrence of an anomaly that is adverse to quality will be entered into the Corrective Action System. The corrective action process provides reasonable assurance that deficiencies adverse to quality are either promptly corrected or are evaluated to be acceptable. Although age-related degradation is not expected for power, instrumentation, and control cables and connectors in their normal environments, visual inspections will provide reasonable assurance that the intended functions will be maintained.

18.2 Existing Aging Management Activities 18.2.1 Augmented Inspection Activities The purpose of the Augmented Inspection Activities is to perform examinations of selected components and supports in accordance with requirements identified in the Technical Specifications, UFSAR, license commitments, industry operating experience, and good practices for the station. Augmented inspections are outside the required scope of ASME Section XI. The scope of Augmented Inspection Activities to be performed during each refueling outage is identified by Engineering in accordance with controlled procedures. Component conditions are monitored to detect degradation due to loss of material and cracking. Inspections include visual, surface, and volumetric examinations.

The extent of each component inspection is defined within the Augmented Inspection Activities program description.

Augmented Inspection Activities include:

• High Energy Lines Outside of Containment (Main Steam and Feedwater)

• Reactor vessel incore detector thimble tubes

• Component supports

• Steam generator feedwater nozzles

• Reactor vessel head

• Turbine throttle valves

• Steam generator supports The Augmented Inspection Activities will also include an inspection of the core barrel hold-down spring. The inspection will address the aging effect of loss of pre-load. The initial inspection will be performed prior to the end of year 40 of operation. Additionally, Augmented Inspection Activities will include an inspection of the pressurizer surge line connection to the reactor coolant system hot-leg loop piping. The inspection will address the aging effect of thermal fatigue failure of the weld due to environmental effects, as described in NRC Generic Safety Issue GSI-190. Inspection details regarding scope, frequency, qualifications, methods, etc. will be submitted to the NRC. The initial inspection will be completed prior to the end of year 40 of operation. Additional inspections will be Page 6

North Anna Power Station, Units 1 and 2 Application for Renewed Operating Licenses Revised UFSAR Supplement performed during each subsequent inspection period. Industry efforts to study the environmental effects on weld thermal fatigue failure will continue to be evaluated by Dominion. If warranted, alternatives to this planned inspection (re-evaluation, replacement, or repair) will be submitted to the NRC.

The acceptance standards for non-destructive examinations for the Augmented Inspection Activities are consistent with guidance provided in ASME Section XI or are provided within applicable examination procedures. Evidence of loss of material, loss of pre-load, or cracking requires engineering evaluation for determination of corrective action. Occurrence of significant degradation that is adverse to quality will be entered into the Corrective Action System. Corrective action provides reasonable assurance that conditions adverse to quality are promptly corrected.

18.2.2 Battery Rack Inspections The purpose of the Battery Rack Inspections is to provide reasonable assurance of the integrity of the supports for various station batteries. Loss of material due to corrosion is the aging effect. Periodic checks of the rack integrity are performed, coincident with periodic battery inspections, to determine the physical condition of the battery support racks. The condition and mechanical integrity of the battery support racks are visually inspected to provide reasonable assurance that their function to adequately support the batteries is maintained. Visual inspections are adequate to identify degradation of the physical condition of the support racks. These inspections check for corrosion of the support rack structural members.

If any material condition deterioration is sufficiently extensive to interfere with integrity of the racks, the Corrective Action System will determine the cause and appropriate action to repair and prevent recurrence of the degradation. Corrective action provides reasonable assurance that conditions adverse to quality are promptly corrected.

18.2.3 Boric Acid Corrosion Surveillance Leakage from borated systems inside Containment creates the potential for degradation of components. Inspections are performed to provide reasonable assurance that borated water leakage does not lead to undetected loss of material from the reactor coolant pressure boundary and surrounding components. Carbon steel is particularly susceptible, but copper also can be damaged.

In Generic Letter 88-05 (Reference 2), the NRC identified concerns with boric acid corrosion of carbon-steel reactor pressure boundary components inside Containment. In response to this generic letter, activities were developed to examine primary coolant components for evidence of borated water leakage that could degrade the external surfaces of nearby structures or components, and to implement corrective actions to address coolant leakage.

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North Anna Power Station, Units 1 and 2 Application for Renewed Operating Licenses Revised UFSAR Supplement Primary coolant systems inside Containment are examined for evidence of borated water leakage. An overall visual inspection of coolant system piping is performed, with particular interest in potential leakage locations. Insulated portions of the coolant systems are examined for signs of borated water leakage through the insulation by examining accessible joints and exposed surfaces of piping and equipment. Vertical components are examined at the lowest elevation. Components and connections that are not accessible are examined by looking for borated water leakage on the surrounding area of the floor or adjacent equipment and insulation. The inspection scope includes connections to the reactor coolant system from the normal coolant letdown and makeup piping, and from the emergency core cooling systems. Components that are in the vicinity of borated water leakage are also examined for damage resulting from the leakage.

The acceptance criterion for visual inspections is the absence of detectable leakage or boric acid residue. Whenever evidence exists of borated water leakage, a visual examination is required, and an engineering evaluation is performed to determine whether degradation of the leaking component or nearby affected components has occurred; and whether the observed condition is acceptable without repair. Occurrence of significant degradation that is adverse to quality is entered into the Corrective Action System. Corrective action provides reasonable assurance that conditions adverse to quality are promptly corrected.

18.2.4 Chemistry Control Program for Primary Systems The purpose of the Chemistry Control Program for Primary Systems is to provide reasonable assurance that water quality is compatible with the materials of construction in the plant systems and equipment in order to minimize the loss of material and cracking.

The Chemistry Control Program for Primary Systems creates an environment in which material degradation is minimized, therefore, maintaining material integrity and reducing the amount of corrosion product that could accumulate and interfere with equipment operation or heat transfer.

Chemistry sampling is performed and the results are monitored and trended by maintaining logs of measured parameters. Acceptability of the measurements is determined by comparison with the limits established in the Chemistry Control Program for Primary Systems. Acceptance criteria for the measured primary chemistry parameters are listed in the Chemistry Control Program for Primary Systems. The acceptance criteria reflect EPRI guidelines for parameters that have been shown to contribute to component degradation. Adherence to the guidelines minimizes the aging effects of loss of material and cracking.

Action levels are established to initiate corrective action when the established limits are approached or exceeded. Depending on the magnitude of the out-of-limit condition, plant shutdown may be performed to minimize aging effects while plant actions are being Page 8

North Anna Power Station, Units 1 and 2 Application for Renewed Operating Licenses Revised UFSAR Supplement taken. Corrective actions for conditions that are adverse to quality are performed in accordance with the Corrective Action System. Corrective action provides reasonable assurance that conditions adverse to quality are promptly corrected.

18.2.5 Chemistry Control Program for Secondary Systems The purpose of the Chemistry Control Program for Secondary Systems is to provide reasonable assurance that water quality is compatible with the materials of construction in the plant systems and equipment in order to minimize the loss of material and cracking.

The Chemistry Control Program for Secondary Systems creates an environment in which material degradation is minimized, therefore, maintaining material integrity and reducing the amount of corrosion product that could accumulate and interfere with equipment operation or heat transfer.

Chemistry results are monitored and trended by maintaining logs of measured parameters. Acceptability of the measurements is determined by comparison with limits established by the Chemistry Control Program for Secondary Systems. Acceptance criteria for the measured secondary chemistry parameters are listed in the Chemistry Control Program for Secondary Systems. The acceptance criteria reflect EPRI guidelines for parameters that have been shown to contribute to component degradation. Adherence to the guidelines minimizes the aging effects of loss of material and cracking.

Action levels are established to initiate corrective action when the established limits are exceeded. Depending on the magnitude of the out-of-limit condition, power is reduced or the plant is shut down to minimize aging effects while plant actions are being taken.

Corrective actions for conditions that are adverse to quality are performed in accordance with the Corrective Action System. Corrective action provides reasonable assurance that conditions adverse to quality are promptly corrected.

18.2.6 Civil Engineering Structural Inspection The maintenance rule, 10 CFR 50.65, requires licensees to monitor the condition of structures against established goals. During the period of extended operation, the provisions of the Maintenance Rule Program will be utilized to provide reasonable assurance of the continuing capability of civil engineering structures to fulfill their intended functions. The scope of Civil Engineering Structural Inspections will be expanded to include inspections required for license renewal, including annual monitoring of groundwater chemistry. This expansion will be implemented prior to the end of year 40 of operation.

Structural monitoring inspections are visual inspections that are performed to assess the overall physical condition of the structure. For concrete structures, this includes elastomer sealant materials.

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North Anna Power Station, Units 1 and 2 Application for Renewed Operating Licenses Revised UFSAR Supplement Inspections are performed by trained inspectors and include representative samples of both the interior and exterior accessible surfaces of structures. Documentation of inspection results includes a general description of observed conditions, location and size of anomalies, and the noted effects of environmental conditions. If an inaccessible area becomes accessible by such means as dewatering, excavation or installation of radiation shielding, an opportunity will exist for additional inspections. Prior to the end of year 40 of operation, guidance will be provided in plant procedures to take advantage of such inspection opportunities when they arise for inaccessible areas.

A visual indication of: 1) loss of material for concrete and structural steel, 2) significant cracking for concrete and masonry walls, 3) change in material properties for elastomers,

4) loss of material or loss of form for soil, and 5) gross indications of change in material properties of concrete, each requires an engineering evaluation.

Inspections of masonry walls are included in this program. The inspections check for cracks of joints and missing or broken blocks.

The engineering evaluation of inspection results, including groundwater chemistry results, determines whether analysis, repair, or additional inspections or testing is required to provide reasonable assurance that structures will continue to fulfill their intended functions. Corrective actions for conditions that are adverse to quality are performed in accordance with the Corrective Action System. Corrective action provides reasonable assurance that conditions adverse to quality are promptly corrected.

18.2.7 Fire Protection Program Regulatory requirements associated with fire protection systems and implementation plans are provided in 10 CFR 50.48 and 10 CFR 50, Appendix R. The Fire Protection Plan includes applicable National Fire Protection Association commitments and maintains compliance with NRC Branch Technical Position (BTP) 9.5-1 from the Standard Review Plan (Reference 3). Aging management concerns related to fire protection involve visual inspections of fire protection equipment and barriers, including doors, walls, floors, ceilings, penetration seals, fire-retardant coatings, fire dampers, cable-tray covers, and fire stops.

Applicable aging effects that are found by visual examination include loss of material, separation and cracking/delamination, heat transfer degradation, and change in material properties. Aging effects on piping systems (including valve bodies and pump casings) that are dry or that carry water are evaluated in the same manner as for any other mechanical system. Testing of the fire protection pumps provides indication of heat transfer degradation, and inspections of the pumps provide indication of loss of material.

Verification of piping integrity to maintain a pressure boundary for the fire protection system, and the availability of water are addressed by routine plant walkdowns, by Page 10

North Anna Power Station, Units 1 and 2 Application for Renewed Operating Licenses Revised UFSAR Supplement pressure/flow tests that are conducted periodically, and by the Work Control Process.

Visual inspections are performed periodically for hose stations, hydrants, and sprinklers.

Provisions to replace sprinklers or test a representative sample of sprinklers that have been in service for 50 years will be incorporated into the Fire Protection Program. This task conforms to the requirements of NFPA-25, Section 2-3.1.1. If testing is performed, re-testing will be performed at 10 year intervals per NFPA-25.

Fire protection equipment is examined for indications of visible damage. Acceptable sizes for breaks, holes, cracks, gaps, or clearances in fire barriers, and acceptable amounts of sealant in penetrations are established in the inspection procedures. Any questions regarding the ability of the barrier to fulfill its fire protection function are addressed by engineering evaluation. Acceptance criteria for fire protection equipment performance tests (i.e., flow and pressure tests) are provided in the appropriate test procedures.

Occurrence of significant degradation that is adverse to quality is entered into the Corrective Action System. Corrective action provides reasonable assurance that conditions adverse to quality are promptly corrected.

18.2.8 Fuel Oil Chemistry The Fuel Oil Chemistry program manages the loss of material by requiring that oil quality is compatible with the materials of construction in plant systems and equipment. Poor fuel oil quality could lead either to degradation of storage tanks or accumulations of particulates or biological growth in the tanks. The purpose of the Fuel Oil Chemistry program is to minimize the existence of contaminants such as water, sediment, and bacteria which could degrade fuel oil quality and damage the fuel oil system and interfere with the operation of safety-related equipment.

The Fuel Oil Chemistry program is an aging effects mitigation activity which does not directly detect aging effects. The Fuel Oil Chemistry guidelines address the parameters to be monitored and the acceptance limit for each parameter. The acceptance criteria reflect ASTM guidelines for parameters that have been shown to contribute to component degradation. Adherence to the guidelines mitigates the aging effect of loss of material.

Parameters analyzed and found to be outside established limits will be reported to Engineering, an evaluation will be performed, and appropriate corrective actions will be taken. Occurrence of significant deviations that are adverse to quality is entered into the Corrective Action System. Corrective action provides reasonable assurance that conditions adverse to quality are promptly corrected.

18.2.9 General Condition Monitoring Activities General Condition Monitoring Activities are performed for the assessment and management of aging for components that are located in normally accessible areas. The results of this monitoring are the basis for initiating required corrective action in a timely Page 11

North Anna Power Station, Units 1 and 2 Application for Renewed Operating Licenses Revised UFSAR Supplement manner. This monitoring is based on the observations that are made during focused inspections that are performed on a periodic basis. Guidance will be developed and implemented in procedures for engineers and health physics technicians regarding inspection criteria that focus on detection of aging effects during General Condition Monitoring Activities. This guidance will be provided prior to the end of year 40 of operation.

The external condition of supports, piping, doors, and equipment will be determined by visual inspection. General Condition Monitoring Activities are performed in three different ways:

• Inspections of radiologically controlled areas for borated water leakage

• Periodic focused inspections such as system walkdowns

• Area inspections for condition of structural supports and doors Inspection criteria for non-ASME Section XI component supports and doors, as part of General Condition Monitoring, will be developed. Initial inspections will be completed, using the criteria, prior to the end of year 40 of operation.

These inspections provide information to manage the aging effects of loss of material, change in material properties, and cracking.

The acceptance criteria for visual inspections are identified in procedures that direct the various monitoring activities. Responsibility for the evaluation of identified visual indications of aging effects is assigned to Engineering personnel. Evaluations of anomalies found during General Condition Monitoring Activities determine whether analysis, repair, or further inspection is required. Occurrence of significant degradation that is adverse to quality is entered into the Corrective Action System. Corrective action provides reasonable assurance that conditions adverse to quality are promptly corrected.

18.2.10 Inspection Activities - Load Handling Cranes and Devices The load handling cranes within the scope of license renewal are listed below:

• Containment polar cranes

• Containment jib cranes

• Containment annulus monorails

• Refueling manipulator cranes

• Fuel handling bridge crane

• New fuel transfer elevator

• Spent fuel crane

• Auxiliary Building monorails Page 12

North Anna Power Station, Units 1 and 2 Application for Renewed Operating Licenses Revised UFSAR Supplement The long-lived passive components of these cranes that are subject to aging management review include rails, towers, load trolley steel, fasteners, base plates, and anchorage. An internal inspection of representative sections of the box girders for the polar cranes will be implemented as a one-time only inspection. This inspection will be performed between year 30 and 40 of operation. An engineering evaluation will determine whether subsequent inspections are required.

The Inspection Activities - Load Handling Cranes and Devices has been developed in accordance with ASME B30.2 (Reference 13) and the inspection activities for monorails are developed in accordance with ASME B30.11 (Reference 14).

The Work Control Process directs structural integrity inspections of applicable cranes which include specific steps to check (visually inspect) the condition of structural members and fasteners on the cranes, the runways along which the cranes move, and the baseplates and anchorages for the runways. The applicable aging effect is identified as loss of material. If the nature of any identified discrepancies is such that corrective action can be completed within the scope of the procedure performing the inspection, no additional corrective action may be necessary. Corrective actions for conditions that are adverse to quality are performed in accordance with the Corrective Action System.

Corrective action provides reasonable assurance that conditions adverse to quality are promptly corrected.

18.2.11 ISI Program - Component and Component Support Inspections The ISl Program - Component and Component Support Inspections are performed in accordance with the requirements of Subsections IWB, IWC, and IWF of ASME XI, Rules for Inservice Inspection of Nuclear Power Plant Components. For this program, the license renewal concerns with respect to Subsection IWC include only the carbon steel piping that is susceptible to high energy line breaks in the feedwater and main steam systems. Inservice Inspection requirements may be modified by applicable Relief Requests and Code Cases, which are approved by the NRC specifically for each unit.

The scope and details of the inspections to be performed are contained in the individualized Inservice Inspection Plan for each unit. Each Inservice Inspection Plan is developed and approved by the NRC for a 120-month inspection interval. The examinations required by ASME Section Xl utilize visual, surface, and volumetric inspections to detect loss of material, cracking, gross indications of loss of pre-load, and gross indications of reduction in fracture toughness (which presents itself as cracking of cast-austenitic stainless steel valve bodies due to thermal embrittlement).

Dominion actively participates in the EPRI-sponsored Materials Reliability Project Industry Task Group on thermal fatigue which currently is developing industry guidance for the management of fatigue caused by cyclic thermal stratification and environmental effects. Dominion is committed to following industry activities related to failure Page 13

North Anna Power Station, Units 1 and 2 Application for Renewed Operating Licenses Revised UFSAR Supplement mechanisms for small-bore piping and will evaluate changes to inspection activities based on industry recommendations.

Acceptance standards for inservice inspections are identified in Subsection IWB for Class 1 components, Subsection IWC for included Class 2 components, and in Subsection IWF for component supports. Table IWB 2500-1 refers to acceptance standards listed in paragraph IWB 3500. Anomalous indications beyond the criteria set forth in the Code acceptance standards that are revealed by the inservice inspections of Class 1 components may require additional inspections of similar components in accordance with Section XI. Evidence of loss of material, cracking, and gross indications of either loss of pre-load or reduction of fracture toughness requires engineering evaluation for determination of corrective action. Occurrence of significant degradation that is adverse to quality will be entered into the Corrective Action System. Corrective action provides reasonable assurance that conditions adverse to quality are promptly corrected.

18.2.12 ISI Program - Containment Inspection The ISI Program - Containment Inspection for concrete containments and containment steel liners implements the requirements in 10 CFR 50.55a and Subsections IWE and IWL of ASME Section XI, 1992 edition through 1992 addenda. The program incorporates applicable code cases and approved relief requests. The provisions of 10 CFR 50.55a are invoked for inaccessible areas within the Containment structure.

Loss of material is the aging effect for the containment steel liner. Surface degradation and wall thinning are checked by visual and volumetric examinations. The frequency and scope of examination requirements are specified in 10 CFR 50.55a and Subsection IWE.

Loss of material, cracking and change in material properties are the aging effects for the containment concrete and are checked by visual examinations. The frequency and scope of examination requirements are specified in 10 CFR 50.55a and Subsections IWL.

These inspections provide reasonable assurance that aging effects associated with the containment liner and concrete are detected prior to compromising design basis requirements. The evaluations of accessible areas provide the basis for extrapolation to the expected condition of inaccessible areas, and an assessment of degradation in such areas.

During the course of containment inspections, anomalous indications are recorded on inspection reports that are kept in Station Records. Acceptance standards for the IWE inspections are identified in ASME Section Xl Table IWE 2500-1 and refer to 10 CFR 50, Appendix J. For the IWL inspections, acceptance standards are identified in ASME Section XI Table IWL 2500-1. Engineering evaluations are performed for inspection results that do not meet established acceptance standards. Occurrence of significant degradation that is adverse to quality will be entered into the Corrective Action System.

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North Anna Power Station, Units 1 and 2 Application for Renewed Operating Licenses Revised UFSAR Supplement Corrective action provides reasonable assurance that conditions adverse to quality are promptly corrected.

18.2.13 ISI Program - Reactor Vessel The ISI Program - Reactor Vessel is performed in accordance with the requirements of Subsection IWB of ASME XI, Rules for Inservice Inspection of Nuclear Power Plant Components. Inservice Inspection requirements may be modified by applicable Relief Requests and Code Cases, which are approved by the NRC specifically for each unit.

The scope and details of the inspections to be performed are contained in the individualized Inservice Inspection Plan for each unit. Each Inservice Inspection Plan is developed and approved by the NRC for a 120-month inspection interval. Dominion will follow industry efforts (in addition to the existing reliance on chemistry control and ASME Section XI inspections) regarding inspection of core support lugs. Industry recommendations will be considered to determine the need for enhanced inspections.

In accordance with ASME Section XI, reactor vessel components are inspected using a combination of surface examinations, volumetric examinations, and visual examinations to detect the aging effects of loss of material, cracking, gross indications of loss of pre-load, and gross indications of reduction in fracture toughness. Acceptance standards for inservice inspections are identified in Subsection IWB for Class 1 components. Table IWB 2500-1 refers to acceptance standards listed in paragraph IWB 3500. Anomalous indications that are revealed by the inservice inspections may require additional inspections of similar components, in accordance with Section XI. Evidence of aging effects requires engineering evaluation for determination of corrective action. Occurrence of significant degradation that is adverse to quality is entered into the Corrective Action System. Corrective action provides reasonable assurance that conditions adverse to quality are promptly corrected.

18.2.14 Reactor Vessel Integrity Management The scope of the Reactor Vessel Integrity Management activities is focused on ensuring adequate fracture toughness of the reactor vessel beltline plate and weld materials.

Neutron dosimetry and material properties data derived from the reactor vessel materials irradiation surveillance program are used in calculations and evaluations that demonstrate compliance with applicable regulations. The Reactor Vessel Integrity Management activities includes the following aspects:

• Irradiated sample (capsule) surveillance.

• Vessel fast neutron fluence calculations.

• Measurements and calculations of nil-ductility transition temperature (RTNDT) for vessel beltline materials.

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North Anna Power Station, Units 1 and 2 Application for Renewed Operating Licenses Revised UFSAR Supplement

• Measurements and calculations of Charpy Upper Shelf Energy (CvUSE).

• Calculation of reactor coolant system pressure-/temperature (P-T operating limits, and Low Temperature Overpressure Protection System setpoints.

• Pressurized Thermal Shock screening calculations.

Specimen capsules were placed in each of the reactors prior to initial irradiation and contain reactor vessel plate and weld material samples. The baseline mechanical properties of reactor vessel steels are determined from pre-irradiation testing of Charpy V-notch and tensile specimens. Post-irradiation testing of similar specimens provides a measure of radiation damage.

Fast neutron irradiation is the cause of radiation damage to the reactor vessel beltline.

The results of surveillance capsule dosimetry analyses are used as benchmarks for calculations of neutron fluence to the surveillance capsules and to the reactor vessel beltline.

Measured values of Charpy transition temperature and CvUSE are obtained from mechanical testing of irradiation surveillance program specimens. Measured values of transition temperature are used to determine the reference temperature for nil-ductility transition (RTNDT) for the limiting reactor vessel beltline material. RTNDT is a key analysis input for the determination of reactor coolant system pressure-temperature operating limits and LTOPS setpoints. Measured values of transition temperature shift are similarly utilized in PTS screening calculations required by 10 CFR 50.61. Measured values of CvUSE are used to verify compliance with the upper shelf energy requirements of 10 CFR 50 Appendix G.

Acceptable values are established for the following parameters:

"* Heatup and cooldown limits, as implemented by Technical Specifications, to ensure reactor vessel integrity.

"* A pressurized thermal shock reference temperature that is within the screening criteria of 10 CFR 50.61.

"* A fast fluence value for the surveillance capsule that bounds the expected fluence at the affected vessel beltline material through the period of extended operation.

"* Charpy Upper Shelf Energy (CvUSE) greater than limits set forth in 10 CFR 50, Appendix G.

Based on established parameters, calculations are performed to ensure that the units will remain within the acceptable values.

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North Anna Power Station, Units 1 and 2 Application for Renewed Operating Licenses Revised UFSAR Supplement 18.2.15 Reactor Vessel Internals Inspection Visual inservice inspections are implemented in accordance with Category B-N-3 (Removable Core Support Structures) of ASME Section XI, Subsection IWB, to determine the possible occurrence of age-related degradation. These inspections are performed at 10-year intervals in accordance with the inspection plans approved by the NRC. The scope of components that comprise the reactor internals includes the upper and lower core internals assemblies. This includes core support and hold-down spring components, as well as, the baffle/former bolting and barrel/former bolting. Additionally, a one-time focused inspection of the reactor vessel internals will be performed between year 30 and 40 of operation. The one-time inspection will look for indications of the presence of aging effects identified in the aging management review for the reactor vessel internals. The inspection will be performed on one reactor (at either Surry or North Anna) and an engineering evaluation of results will determine the need for inspections of the other units.

Dominion will remain active in industry groups, including the EPRI-sponsored Materials Reliability Project Industry Task Group, to stay aware of any new industry recommendations regarding such aging management issues as neutron embrittlement, void swelling, and the synergistic effect of thermal and neutron embrittlement of internals sub-components. If future industry developments suggest the need for an alternate inspection plan during the period of extended operation, or negate the need for a one-time inspection, then Dominion will modify the proposed inspection plan.

Visual inspections are utilized to detect loss of material and cracking; as well as, gross indications of loss of pre-load and/or reduced fracture toughness. The acceptance standards for the visual examinations are summarized in ASME Subsection IWB-3520.2, Visual Examination, VT-3. These inspections are directed to be performed with the internals assemblies removed from the reactor vessel.

Acceptance standards for Reactor Vessel Internals Inspection activities are identified in ASME Section XI, Subsection IWB. Table IWB 2500-1 identifies references to the acceptance standards listed in Paragraph IWB 3500. Anomalous indications, that are revealed to be beyond the criteria in the acceptance standards by the inservice inspections, may require additional inspections. Evidence of any component degradation requires engineering evaluation for determination of corrective action. Occurrence of significant degradation that is adverse to quality is entered into the Corrective Action System. Corrective action provides reasonable assurance that conditions adverse to quality are promptly corrected.

18.2.16 Secondary Piping and Component Inspection The purpose of the Secondary Piping and Component Inspection program is to identify, inspect, and trend components that are susceptible to the aging effect of loss of material as a result of Flow Accelerated Corrosion (FAC) in either single or two-phase flow Page 17

North Anna Power Station, Units 1 and 2 Application for Renewed Operating Licenses Revised UFSAR Supplement conditions. This program has been implemented in accordance with NRC Generic Letter 89-08, Erosion/Corrosion-Induced Pipe Wall Thinning (Reference 15), and NUREG-1344, Erosion/Corrosion-Induced Pipe Wall Thinning in U.S. Nuclear Power Plants (Reference 16), and EPRI Guideline NSAC-202L, Recommendations for an Effective Flow Accelerated Corrosion Program (Reference 17).

The scope of the Secondary Piping and Component Inspection program includes portions of the feedwater systems, the main and auxiliary steam systems, and the steam generator blowdown lines.

The Secondary Piping and Component Inspection program also includes susceptible vent and drain lines.

The identification of components and piping segments to be included in each Secondary Piping and Component Inspection effort is performed by Engineering using plant chemistry data, past inspection data, predictions from FAC-monitoring computer codes, and industry experience. Determination of whether a piping component has experienced FAC degradation is made by measuring the current wall thickness using the UT method and comparing against previous baseline thickness measurement, if available. Visual inspections of the internals of non-piping components, such as pumps and valves, are performed as the equipment is opened for other repairs and/or maintenance, to determine whether flow-accelerated degradation is occurring.

The decision to repair or replace a component is made by Engineering. For the internal surface examinations, engineering evaluations are utilized to determine whether the results of visual inspections indicate conditions that require corrective action.

Occurrences of significant degradation that are adverse to quality are entered into the Corrective Action System. Corrective action provides reasonable assurance that conditions adverse to quality are promptly corrected.

18.2.17 Service Water System Inspections Compliance with Generic Letter 89-13 (Reference 18) requires a variety of inspections, non-destructive examinations, and heat transfer testing for components cooled by service water. Generic Letter 89-13 directed utilities to assess the following aspects of operational problems with service water cooling systems:

• Biofouling

• Heat Transfer Testing

• Routine Inspection and Maintenance

• Single-failure Walkdown

• Procedure Review Page 18

North Anna Power Station, Units 1 and 2 Application for Renewed Operating Licenses Revised UFSAR Supplement The Service Water System Inspections program provides reasonable assurance that corrosion (including microbiologically-influenced corrosion, MIC), erosion, protective coating failure, silting, and biofouling of service water piping and components will not cause a loss of intended function. The primary objectives of this program are to (1) remove excessive accumulations of biofouling agents, corrosion products, and silt; and (2) repair defective protective coatings and degraded service water system piping and components that could adversely affect performance. Preventive maintenance, inspection, and repair procedures have been developed to provide reasonable assurance that any adverse effects of exposure to service water are adequately addressed. The addition of biocide to the service water system reduces biological growth (including MIC) that could lead to degradation of components exposed to the service water. Additionally, a one-time measurement of sludge buildup in the service water reservoir will be performed.

This measurement will be completed between year 35 and 40 of operation.

Service Water System Inspections are performed to check for biofouling, damaged coatings, and degraded material condition. Heat transfer parameters for components cooled by service water are monitored. Visual inspections are performed to check for loss of material and changes in material properties. Heat transfer testing is performed to identify the aging effects of loss of material and heat transfer degradation.

Volumetric inspections are also performed to check for loss of material due to MIC.

The acceptance criteria for visual inspections are identified in the procedures that perform the individual inspections. The procedures identify the type and degree of anomalous conditions that are signs of degradation. In the case of service water, degradation includes biofouling as well as material degradation. Engineering evaluations determine whether observed deterioration of material condition is sufficiently extensive to lead to loss of intended function for components exposed to the service water. An engineering evaluation will also determine if additional sludge measurements in the service water reservoir are needed. The degraded condition of material or of heat transfer capability may require prompt remediation. Occurrence of significant degradation that is adverse to quality is entered into the Corrective Action System. Corrective action provides reasonable assurance that conditions adverse to quality are promptly corrected.

18.2.18 Steam Generator Inspections Steam Generator Inspections are performed in accordance with Technical Specifications and Inservice Inspection requirements of ASME Section Xl. Steam Generator Inspections plans are based upon the guidelines established by Nuclear Energy Institute document, NEI 97-06 (Reference 4) and the Electric Power Research Institute steam generator inspection guidelines (Reference 5). Steam generator tubing inspections are performed on a sampling basis. The sample population inspected meets or exceeds the Page 19

North Anna Power Station, Units 1 and 2 Application for Renewed Operating Licenses Revised UFSAR Supplement requirements of Technical Specifications. Qualified techniques, equipment and personnel are used for inspections in accordance with site-specific eddy current analysis guidelines.

Examination of steam generator sub-components other than tubes are performed as required by the governing edition and addenda of ASME Section Xl, as imposed by 10 CFR 50.55a. In some cases the specific inspection requirements of ASME Section X1 are modified by regulatory commitments and approved Relief Requests. Inspections of the steam generators to check for loss of material, cracking, and gross indications of loss of pre-load include a combination of visual inspections, surface examinations, and volumetric examinations. Tubing inspections are performed in accordance with ASME Section XI, Subsection IWB.

Acceptance standards for steam generator inspections are provided in ASME Section XI, Subsections IWB-3500 and IWC-3500. Evidence of component degradation requires engineering evaluation for determination of corrective action. Occurrence of significant degradation that is adverse to quality will be entered into the Corrective Action System.

Corrective action provides reasonable assurance that conditions adverse to quality are promptly corrected.

18.2.19 Work Control Process Performance testing and maintenance activities, both preventive and corrective, are planned and conducted in accordance with the station's Work Control Process. The Work Control Process integrates and coordinates the combined efforts of Maintenance, Engineering, Operations, and other support organizations to manage maintenance and testing activities. Performance testing on heat exchangers evaluates the heat transfer capability of the components to determine if heat transfer degradation is occurring.

Maintenance activities provide opportunities for inspectors who are QMT or VT qualified to visually inspect the surfaces (internal and external) of plant components and adjacent piping. Adjacent piping is primarily the internal piping surfaces immediately adjacent to a system component that is accessible through the component for visual inspection. Visual inspections performed through the Work Control Process provide data that can be used to determine the effectiveness of the Chemistry Control Program for Primary Systems and Chemistry Control Program for Secondary Systems to mitigate the aging effects of cracking, loss of material, and change of material properties.

Changes to procedures to reasonably assure that consistent inspections of components are completed during the process of performing work activities (Work Control Process) will be implemented prior to the end of year 40 of operation.

The Work Control Process also provides opportunities through preventive maintenance sampling (predictive analysis) to collect lubricating oil and engine coolant samples for Page 20

North Anna Power Station, Units 1 and 2 Application for Renewed Operating Licenses Revised UFSAR Supplement subsequent analysis of contaminants that would provide early indication of an adverse environment that can lead to material degradation.

The inspections, testing, and sampling performed under the Work Control Process provide reasonable assurance that the following aging effects will be detected:

• loss of material

• cracking

• heat transfer degradation

• separation and cracking/delamination

• change in material properties The acceptance criteria for visual inspections, testing, or sampling are currently identified in the procedures that perform the individual maintenance, testing, or sampling activity.

The procedures identify the type and degree of anomalous conditions that are signs of degradation.

Whenever evidence of aging effects exists, an engineering evaluation is performed to determine whether the observed condition is acceptable without repair. Occurrence of significant aging effects that is adverse to quality is entered into the Corrective Action System. If the evaluation of an anomalous condition indicates that the occurrence was unexpected for the operational conditions involved, the Work Control Process will be used to ensure that locations with similar material and environmental conditions will be inspected.

As confirmation that the Work Control Process has inspected representative components from each component group for which the Work Control Process is credited to manage the effects of aging, periodic audits of inspections actually performed will be performed and, if Work Control Process activities are found not to be representative, supplemental inspections will be performed. Two audits of the Work Control Process are anticipated, and each will consist of a review of the previous 10 years of historical data. One audit will be performed prior to 40 years of plant operation, and another will be performed at approximately 50 years of plant operation. Any required supplemental inspections would be completed within 5 years after the audits are performed.

18.2.20 Corrective Action System The Corrective Action System is a required element of the Quality Assurance Program outlined in the Quality Assurance Topical Report (Chapter 17 of the Updated Final Safety Analysis Report). The Quality Assurance Program implements the requirements of 10 CFR 50, Appendix B, and is consistent with the summary in Section A.2 of NUREG-1 800, Standard Review Plan for License Renewal. The Corrective Action System activities include the elements of corrective action, confirmation process, and administrative Page 21

North Anna Power Station, Units 1 and 2 Application for Renewed Operating Licenses Revised UFSAR Supplement controls; and is applicable to the safety-related and non-safety-related structures, systems, and components that are within the scope of license renewal.

18.3 Time-Limited Aging Analysis As part of the application for a renewed license, 10 CFR 54.21(c) requires that an evaluation of time-limited aging analyses (TLAAs) for the period of extended operation be provided. The following TLAAs have been identified and evaluated to meet this requirement.

18.3.1 Reactor Vessel Neutron Embrittlement The reactor vessel is subjected to neutron irradiation from the core. This irradiation results in the embrittlement of the reactor vessel materials. Analyses have been performed that address the following:

"* Upper shelf energy

"* Pressurized thermal shock

"* RCS pressure-temperature operating limits 18.3.1.1 Upper Shelf Energy The Charpy V-notch test provides information about the fracture toughness of reactor vessel materials. 10 CFR 50 requires the Charpy upper shelf energy (CvUSE) of reactor vessel beltline materials to meet Appendix G requirements. If the USE of a reactor vessel beltline material is predicted to not meet Appendix G requirements, then licensees must submit an analysis that demonstrates an equivalent margin of safety at least three years prior to the time the material is predicted to not meet those requirements.

Reactor vessel calculations have been performed which demonstrated that the upper shelf energy values of limiting reactor vessel beltline materials at the end of the period of extended operation meet Appendix G requirements. Thus, the TLAA has been projected to the end of the period of extended operation and is found to be adequate.

18.3.1.2 Pressurized Thermal Shock A limiting condition on reactor vessel integrity, known as pressurized thermal shock (PTS), may occur during postulated system transients, such as a loss-of-coolant accident (LOCA) or a steam line break. Such transients may challenge the integrity of the reactor vessel under the following conditions: severe overcooling of the inside surface of the vessel wall followed by high re-pressurization, significant degradation of vessel material toughness caused by radiation embrittlement, and the presence of a critical-size defect in the vessel wall.

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North Anna Power Station, Units 1 and 2 Application for Renewed Operating Licenses Revised UFSAR Supplement The reference temperature for pressurized thermal shock (RTPTS) is defined in 10 CFR 50.61. RTPTS values for the limiting reactor vessel materials at the end of the period of extended operation have been recalculated by Dominion. At the end of the period of extended operation, the calculated RTPTS values for the beltline materials are less than the applicable screening criteria established in 10 CFR 50.61. Thus, the TLAA has been projected to the end of the period of extended operation and is found to be adequate.

18.3.1.3 Pressure-Temperature Limits Atomic Energy Commission (AEC) General Design Criterion (GDC) 14 of Appendix A of 10 CFR 50, "Reactor Coolant Pressure Boundary," requires that the reactor coolant pressure boundary be designed, fabricated, erected, and tested to have an extremely low probability of abnormal leakage (or rapid failure) and of gross rupture. AEC GDC 31, "Fracture Prevention of Reactor Coolant Pressure Boundary," requires that the reactor coolant pressure boundary be designed with sufficient margin to ensure that when stressed under operating, maintenance, and testing conditions the boundary behaves in a non-brittle manner and the probability of rapidly propagating fracture is minimized.

Reactor vessel neutron fluence values corresponding to the end of the period of extended operation and reactor vessel beltline material properties were used to determine the limiting value of reference nil ductility reference temperature (RTNDT), and to calculate RCS pressure-temperature (P-T) operating limits valid through the end of a period of extended operation. Maximum allowable low temperature overpressure protection system (LTOPS) power operated relief valve (PORV) lift setpoints have been developed on the basis of the P-T limits applicable to the period of extended operation. Revised RCS P-T limit curves and LTOPS setpoints will be submitted for review and approval prior to the expiration of the existing technical specification limits in order to maintain compliance with the governing requirements of 10 CFR 50 Appendix G.

The TLAA has been projected to the end of the period of extended operation and is found to be adequate.

18.3.2 Metal Fatigue The thermal fatigue analyses of the station's mechanical components have been identified as time-limited aging analyses.

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North Anna Power Station, Units 1 and 2 Application for Renewed Operating Licenses Revised UFSAR Supplement 18.3.2.1 ASME Boiler and Pressure Vessel Code,Section III, Class 1 The steam generators, pressurizers, reactor vessels, loop stop valves, reactor coolant pumps, control rod drive mechanisms (CRDMs), and all reactor coolant system pressure boundary piping have been analyzed using the methodology of the ASME Boiler and Pressure Vessel Code,Section III, Class 1.

The ASME Boiler and Pressure Vessel Code,Section III, Class 1, requires a design analysis to address fatigue and establish limits such that the initiation of fatigue cracks is precluded.

Experience has shown that the transients used to analyze the ASME III requirements are often very conservative. Design transient magnitude and frequency are more severe than those occurring during plant operation. The magnitude and number of the actual transients are monitored. This monitoring assures that the existing frequency and magnitude of transients are conservative and bounding for the period of extended operation, and that the existing ASME III equipment will perform its intended functions for the period of extended operation. A cycle counting program (Section 18.4.2) is in place to provide reasonable assurance that the actual transients are smaller in magnitude and within number of the transients used in the design.

Fatigue analyses for the steam generators, pressurizers, reactor vessels, reactor coolant pumps, CRDMs, and all RCS pressure boundary piping have been evaluated and determined to remain valid for the period of extended operation.

Fatigue analyses for the reactor vessel closure studs and the loop stop valves have been re-analyzed. The analyses for these components have been projected to be valid for the period of extended operation.

18.3.2.2 Reactor Vessel Underclad Cracking In early 1971, an anomaly was identified in the heat-affected zone of the base metal in a European-manufactured reactor vessel. A generic fracture mechanics evaluation by Westinghouse demonstrated that the growth of underclad cracks during a 40-year plant life would be insignificant.

The evaluation was extended to 60 years using fracture mechanics evaluation based on a representative set of design transients. The occurrences were extrapolated to cover 60 years of service life. This 60-year evaluation shows insignificant growth of the underclad cracks and is documented in WCAP-15338 (Reference 21). The plant-specific design transients are bounded by the representative set used in the evaluation.

The analysis associated with reactor vessel underclad crack growth has been projected to the end of the period of extended operation and has been found to be acceptable.

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North Anna Power Station, Units 1 and 2 Application for Renewed Operating Licenses Revised UFSAR Supplement 18.3.2.3 ANSI B31.1 Piping The balance-of-plant piping is designed to the requirements of ANSI B31.1, "Power Piping."

ANSI B31.1 design requirements assume a stress range reduction factor in order to provide conservatism in the piping design while accounting for fatigue due to thermal cyclic operation. This reduction factor is 1.0, provided the number of anticipated cycles is limited to 7,000 equivalent full-temperature cycles. A piping system would have to be thermally cycled approximately once every three days over a plant life of 60 years to reach 7,000 cycles. Considering this limitation, a review of the ANSI B31.1 piping within the scope of license renewal has been performed to identify those systems that operate at elevated temperature and to establish their cyclic operating practices. Under current plant operating practices, piping systems within the scope of license renewal are only occasionally subject to cyclic operation. Typically, these systems are subjected to continuous steady-state operation. Significant variation in operating temperatures occur only during plant heatup and cooldown, during plant transients, or during periodic testing.

The analyses associated with ANSI B31.1 piping fatigue have been evaluated and determined to remain valid for the period of extended operation except for sample lines for the hot and cold legs. The analyses associated with sample lines for the hot and cold legs have been projected to be valid to the end of the period of extended operation.

18.3.2.4 Environmentally Assisted Fatigue Generic Safety Issue (GSI)-190 (Reference 6) identifies a NRC staff concern about the effects of reactor water environments on reactor coolant system component fatigue life during the period of extended operation. The reactor water's environmental effects as described in GSI-190, are not included in the current licensing basis. As a result, the criterion specified in 10 CFR 54.3(a)(6) is not satisfied. Hence, environmental effects are not TLAAs. GSI-190, which was closed in December 1999, has concluded that environmental effects have a negligible impact on core damage frequency, and as such, no generic regulatory action is required (Reference 7). However, as part of the closure of GSI-1 90, the NRC has concluded that licensees who apply for license renewal should address the effects of coolant environment on component fatigue life as part of their aging management programs. As demonstrated in the preceding sections, fatigue evaluation in the original transient design limits remain valid for the period of extended operation.

Confirmation by transient cycle counting will ensure that these transient design limits are not exceeded. Secondly, the reactor water's environmental effects on fatigue life were evaluated using the most recent data from laboratory simulation of the reactor coolant environment.

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North Anna Power Station, Units 1 and 2 Application for Renewed Operating Licenses Revised UFSAR Supplement As a part of the industry effort to address environmental effects for operating nuclear power plants during the current 40-year licensing term, Idaho National Engineering Laboratories evaluated, in NUREG/CR-6260, "Application of NUREG/CR-5999 Interim Fatigue Curves to Selected Nuclear Power Plant Components" (Reference 8),

fatigue-sensitive component locations at plants designed by all four U. S. Nuclear Steam Supply System vendors. The pressurized water reactor calculations, especially the early-vintage Westinghouse PWR calculations, are directly relevant to the Dominion stations. The description of the "Older Vintage Westinghouse Plant" evaluated in NUREG/CR-6260 applies to the North Anna station. In addition, the transient cycles considered in the evaluation match or bound the design. The results of NUREG/CR-6260 analyses, and additional data from NUREG/CR-6583 (Reference 9) and NUREG/CR-5704 (Reference 10), were then utilized to scale up the plant-specific cumulative usage factors (CUF) for the fatigue-sensitive locations to account for environmental effects. Generic industry studies performed by EPRI were also considered in this aspect of the evaluation, as well as environmental data that have been collected and published subsequent to the generic industry studies.

Based on these adjusted CUFs, it has been determined that the surge line connection at the reactor coolant system's hot leg pipe is the leading indicator for reactor water environmental effects. Therefore, the surge line weld at the hot leg pipe connection will be included in an Augmented Inspection Activities (Section 18.2.1).

The potential effects of the reactor water environment have been evaluated for the period of extended operation as required by GSI-1 90.

18.3.3 Environmental Qualification of Electric Equipment 10 CFR 54.49 requires that each holder of a nuclear power plant operating license establish a program for qualifying safety-related electric equipment. Such a program has been implemented at the station and is invoked by Administrative Procedure. Analyses and tests that qualify safety-related equipment for the period of extended operation are considered TLAAs.

The Environmental Qualification Program (Section 18.4.1) requires that all electrical equipment important to safety located in a harsh environment shall be managed through the period of extended operation.

18.3.4 Containment Liner Plate The accumulated fatigue effects of applicable liner loading conditions were evaluated in accordance with Paragraph N-415 of the ASME Boiler and Pressure Vessel Code,Section III, 1968. The evaluation was based on 1,000 cycles of operating pressure variations, 4,000 cycles of operating temperature variations, and 20 design earthquake cycles. The operating pressure variations are anticipated to be less than 100 and Page 26

North Anna Power Station, Units 1 and 2 Application for Renewed Operating Licenses Revised UFSAR Supplement temperature variations are anticipated to be less than 400 for forty years of operation.

Extrapolating these anticipated values for sixty years of operation results in 150 pressure variations and 600 temperature variations (Reference Table 3.8-7). The number of design cycles was conservatively increased to 1,500 cycles of operating pressure variations, 6,000 cycles of operating temperature variation, and 30 design earthquake cycles by using a multiplication factor of 1.5, to account for the period of extended operation.

A review of the identified calculations has determined that the increase in the number of cycles due to the period of extended operation is acceptable. Effects of the Containment Type A pressure tests on fatigue of the Containment liner plate have been included in the evaluation. Therefore, the Containment liner is adequate for a 60-year operating period as currently designed. The analyses associated with the Containment liner plate have been revised and projected to be valid for the period of extended operation.

18.3.5 Plant-Specific Time-Limited Aging Analyses 18.3.5.1 Crane Load Cycle Limit The following are cranes included in license renewal scope and in NUREG-0612 (Reference 11):

• Containment polar cranes

• Containment annulus monorails

• Fuel handling bridge crane

• Spent fuel crane

• Auxiliary Building monorails NUREG-0612 requires that the design of heavy load overhead handling systems meet the intent of Crane Manufacturers Association of America, Inc. (CMAA) Specification #70.

The crane load cycle provided in CMAA-70 has been identified as a TLAA, with the most limiting number of loading cycles being 100,000.

The most frequently used cranes are spent fuel cranes. Each of these cranes will experience approximately 25,000 cycles of half-load lifts to support the refueling of both units over a 60-year period. In addition, the crane is used to load new fuel into the fuel pool, to perform the various rearrangements required by operations support, to accommodate inspections by fuel vendors, and to load spent fuel casks. In such service, the crane is conservatively expected to make a total of 50,000 half-load lifts in a 60-year period.

Therefore, the analyses associated with crane design, including fatigue, are valid for the period of extended operation.

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North Anna Power Station, Units 1 and 2 Application for Renewed Operating Licenses Revised UFSAR Supplement 18.3.5.2 Reactor Coolant Pump Flywheel During normal operation, the reactor coolant pump flywheel possesses sufficient kinetic energy to produce high-energy missiles in the unlikely event of failure, The aging effect of concern is fatigue crack initiation in the flywheel bore keyway. An evaluation of a failure over the period of extended operation has been performed. It demonstrates that the flywheel design has a high structural reliability with a very high flaw tolerance and negligible flaw crack growth over a 60-year service life (Reference 12).

The analysis associated with the structural integrity of the reactor coolant pump flywheel has been evaluated and determined to be valid for the period of extended operation.

18.3.5.3 Leak-Before-Break Westinghouse (Westinghouse Owners Group) tested and analyzed crack growth with the goal of eliminating reactor coolant system primary loop pipe breaks from plant design bases. The objective of the investigation was to examine mechanistically, under realistic yet conservative assumptions - whether a postulated crack causing a leak, will grow to become unstable and lead to a full circumferential break when subjected to the worst possible combinations of plant loading.

The detailed evaluation has shown that double-ended breaks of reactor coolant pipes are not credible, and as a result, large LOCA loads on primary system components will not occur. The overall conclusion of the evaluation was, that, under the worst combination of loading, including the effects of safe shutdown earthquake, the crack will not propagate around the circumference and cause a guillotine break. The plant has leakage detection systems that can identify a leak with margin, and provide adequate warning before the crack can grow.

The concept of eliminating piping breaks in reactor coolant system primary loop piping has been termed "leak-before-break" (LBB).

In 1986, Westinghouse performed an LBB analysis of the primary loop piping. Two TLAAs related to LBB have been identified: fatigue crack growth and thermal aging of cast austenitic stainless steel (CASS). The original fatigue crack growth analysis has been performed for the design transient cycles and with consideration of thermal aging effect for forty years. The steam generator primary nozzles to safe-end welds in the primary loop piping that have been analyzed for LBB are the only components fabricated with Alloy 82/182-weld material for NAPS 1 and 2. Dominion will continue to participate in the ongoing NRC/industry program on Alloy 82/182-weld material and will implement the findings/resolution from this effort, as appropriate.

To maintain the plant's LBB design basis, the thermal aging effect for 60 years has been revalidated. The change in the material property has been found to be insignificant. Since Page 28

North Anna Power Station, Units 1 and 2 Application for Renewed Operating Licenses Revised UFSAR Supplement the number of design transient cycles will not be exceeded during 60 years of operation, the LBB analysis is projected to be valid for the period of extended operation.

18.3.5.4 Spent Fuel Pool Liner The spent fuel pool liner located in the Fuel Building is needed to prevent a leak to the environment. A design calculation has been identified which documents that the spent fuel pool design meets the general industry criteria. The calculation includes a fatigue analysis to add a further degree of confidence.

The normal thermal cycles occur at each refueling, resulting in 80 cycles for both units in 60 years. Total number of thermal cycles is expected to be 90, which includes normal, upset, emergency, and faulted conditions.

The calculations show that the allowable thermal cycles for spent fuel pool liner for the most severe thermal condition, which includes a loss of cooling, is 100.

Therefore, the existing calculations remain valid for the period of extended operation.

18.3.5.5 Piping Subsurface Indications Calculations have been identified that addressed piping subsurface indications detected by inspections, performed in accordance with ASME Section XI. Section Xl provides the acceptance criteria for various flaw orientations, locations and sizes. The calculations determined the number of thermal cycles required for the flaws to reach unacceptable size.

Required cycles for the flaws to reach an unacceptable size are 20,700 or higher.

Since it is expected that the number of the cycles experienced by the piping will not exceed these values for sixty years of operation, the analyses have been determined to remain valid for the period of extended operation.

18.3.5.6 Reactor Coolant Pump and ASME Code Case N-481 Periodic volumetric inspections of the welds in the primary loop pump casings in commercial nuclear power plants are required by Section XI of the ASME Boiler and Pressure Vessel Code. Since the reactor coolant pump casings are inspected prior to being placed in service, and no significant mechanisms exist for crack initiation and propagation; it has been concluded that the inservice volumetric inspection could be replaced with an acceptable alternate inspection. In recognition of this conclusion, ASME Code Case N-481, "Alternative Examination Requirements for Cast Austenitic Pump Casings," provides an alternative to the volumetric inspection requirement. The code case allows the replacement of volumetric examinations of primary loop pump casings with fracture mechanics based integrity evaluations - Item (d) of the code case - supplemented Page 29

North Anna Power Station, Units 1 and 2 Application for Renewed Operating Licenses Revised UFSAR Supplement by specific visual examinations. The analysis has been performed on the reactor coolant pump casing integrity in accordance with the ASME Code Case N-481 requirements. The analysis has been projected to be valid for 60 years.

18.3.6 Exemptions The requirements of 10 CFR 54.21(c) stipulate that the application for a renewed license should include a list of plant-specific exemptions granted pursuant to 10 CFR 50.12 and that are based on time-limited aging analyses, as defined in 10 CFR 54.3. Each active 10 CFR 50.12 exemption has been reviewed to determine whether the exemption is based on a time-limited aging analysis. No plant-specific exemptions granted pursuant to 10 CFR 50.12 and based on a time-limited aging analysis as defined in 10 CFR 54.3 have been identified.

18.4 TLAA Supporting Activities 18.4.1 Environmental Qualification Program The Environmental Qualification (EQ) Program activities are in compliance with the requirements of 10 CFR 50.49. The EQ Program will be continued throughout the period of extended operation. Electrical equipment located in a harsh environment is evaluated for environmental qualification if they are required to function in the conditions that will exist post-accident after being subjected to the normal effects of aging. A harsh environment results from a loss-of-coolant accident (LOCA) or main steam line break inside Containment, high radiation levels due to the post-LOCA effects outside Containment, or high energy line breaks outside Containment.

The EQ Program is applicable to the following groups of components:

"* Safety-related electrical equipment that is relied upon to remain functional during and following a design-basis event (DBE)

"* Non-safety-related electrical equipment whose failure, under postulated environmental conditions, could prevent accomplishment of safety functions

"* Certain post-accident monitoring equipment as described in Regulatory Guide 1.97 (Reference 19).

Guidance regarding environmental qualification was given in NRC Bulletin 79-01B (Reference 20) for Unit 1 and in NUREG-0588 (Category II) (Reference 23) for Unit 2.

The Equipment Qualification Master List (EQML) provides a listing of electrical equipment that is important to safety and is located in a potentially harsh environment.

Based on the definitions of 10 CFR 54, certain EQ calculations are considered to be Time-Limited Aging Analyses (TLAA). As stated in 10 CFR 54.21(c) and in NEI 95-10 (Reference 22), analyses for TLAAs utilize one of the following three options:

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North Anna Power Station, Units 1 and 2 Application for Renewed Operating Licenses Revised UFSAR Supplement i) The analyses remain valid for the period of extended operation, ii) The analyses have been projected to the end of extended operation, or iii)The effects of aging will be adequately managed during the period of extended operation.

For purposes of license renewal, EQ components will be evaluated utilizing Option iii in accordance with the EQ Program. EQ concerns for license renewal will consider only those in-scope components that have a qualified lifetime greater than 40 years. Components with a qualified lifetime of less than 40 years already are included in a program of periodic replacement and are not considered TLAAs.

10 CFR 50.49(j) requires that a qualification record be maintained for all equipment covered by the EQ Rule. The qualification process verifies that the equipment is capable of performing its safety function when subjected to various postulated environmental conditions. These conditions include expected ranges of temperature, pressure, humidity, radiation, and accident conditions such as chemical spray and submergence.

The process of qualifying EQ equipment includes analysis, data collection, and data reduction with appropriate assumptions, acceptance criteria and corrective actions.

Qualification Document Reviews (QDRs) provide the basis for qualifying EQ components.

The QDRs provide the following information for each piece of equipment that is qualified:

"* The performance characteristics required under normal, design-basis event (DBE), and post-DBE conditions.

"* The voltage, frequency, load, and other electrical characteristics for which equipment performance can be provided with reasonable assurance.

"* The environmental conditions, including temperature, pressure, humidity, radiation, chemical spray, and submergence, at the location where the equipment must function.

18.4.2 Transient Cycle Counting During normal, upset, and test conditions; reactor coolant system pressure boundary components are subjected to transient temperatures, pressures, and flows, resulting in cyclic changes in internal stresses in the equipment. The cyclic changes in internal stresses cause metal fatigue. Class 1 reactor coolant system components have been designed to withstand a number of design transients without experiencing fatigue failures during their operating life. The purpose of the Transient Cycle Counting is to record the number of normal, upset, and test events, and their sequence that the stationexperiences during operation. Design transients are counted to provide reasonable assurance that plant operation does not occur outside the design assumptions.

The Transient Cycle Counting activities are applicable to the reactor coolant system pressure boundary components for which the design analysis assumes a specific number of Page 31

North Anna Power Station, Units 1 and 2 Application for Renewed Operating Licenses Revised UFSAR Supplement design transients. A summary of reactor coolant system design transients for which transient cycle counting is performed is listed below:

"* Heatups/Cooldowns <100°F/Hr.

"* Step load increase/decrease of 10%

"* Large load reduction of 50%

"* Loss of load >15%

"* Loss of AC power

"* Loss of flow in one loop

"* Full power reactor trip

"* Inadvertent auxiliary pressurizer spray

• Inadvertent safety injection

• Normal charging and letdown return to service

• Charging trip with delayed return to service The aging effect that is managed by counting transient cycles is cracking due to metal fatigue. The Transient Cycle Counting activities monitor transient cycles that have been experienced by each unit and compare the actual number of cycles to a design assumption.

Any concerns related to fatigue are mitigated, as long as the number and magnitude of transient cycles are less than the design assumptions. Approaching a design limit may indicate a situation that is adverse to quality, and would initiate the Corrective Action System. Subsequently, an engineering analysis will determine the design margin remaining, taking credit for the actual magnitude of transients and their sequence to confirm that the allowable factor has not been exceeded.

If warranted, component repair or replacement would be initiated.

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North Anna Power Station, Units 1 and 2 Application for Renewed Operating Licenses Revised UFSAR Supplement 18.5 References

1.

Working Draft of the NRC Standard Review Plan for the Review of License Renewal Applications for Nuclear Power Plants.

2.

Generic Letter 88-05, Boric Acid Corrosion of Carbon Steel Reactor Pressure Boundary Components in PWR Plants, March 17, 1988.

3.

NUREG-0800, Standard Review Plan for the Review of Safety Analysis Reports for Nuclear Power Plants - LWR Edition, US Nuclear Regulatory Commission. (Formerly NUREG-75/087)

4.

NEI 97-06, Steam Generator Program Guidelines, Revision 1, Nuclear Energy Institute.

5.

Power Steam Generator Examination Guidelines, TR-107569, Electric Power Research Institute.

6.

Generic Safety Issue (GSI)-1 90, Fatigue Evaluation for Metal Components for 60-year Plant Life, U.S. Nuclear Regulatory Commission, August 1996.

7.

Memorandum from Ashok C. Thadani, to William D. Travers, U.S. Nuclear Regulatory Commission, Closeout of Generic Safety Issue 190, December 26, 1999.

8.

NUREG/CR-6260, Application of NUREG/CR-5999 Interim Fatigue Curves to Selected Nuclear Power Plant Components, U.S. Nuclear Regulatory Commission, March 1995.

9.

NUREG/CR-6583, Effects of LWR Coolant Environments on Fatigue Design Curves of Carbon and Low-Alloy Steels, U.S. Nuclear Regulatory Commission, March 1998.

10. NUREG/CR-5704, Effects of LWR Coolant Environments on Fatigue Design Curves of Austenitic Stainless Steels, U.S. Nuclear Regulatory Commission, April 1999.

11.

NUREG-0612, Control of Heavy Loads at Nuclear Power Plants, U.S. Nuclear Regulatory Commission, July 1980.

12. WCAP-1 4535A, Topical Report On Reactor Coolant Pump Flywheel Inspection Elimination, Westinghouse Electric Corporation, November 1996.

13. American National Standards Institute: ANSI B30.2-1976, Overhead and Gantry Cranes.

14. American National Standards Institute:

ANSI B30.11-1973, Monorail Systems and Underhung Cranes.

15. Generic Letter 89-08, Erosion/Corrosion-Induced Pipe Wall Thinning, May 2, 1989.

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North Anna Power Station, Units 1 and 2 Application for Renewed Operating Licenses Revised UFSAR Supplement

16. NUREG-1344, Erosion/Corrosion-Induced Pipe Wall Thinning in US Nuclear Power Plants, April 1, 1989.

17. NSAC-202L, Recommendation for an Effective Flow Accelerated Corrosion Program, Electric power Research Institute, April 8, 1999.

18. Generic Letter 89-13, Service Water System Problems Affecting Safety-Related Equipment, July 18, 1989 (Supplement 1 dated 4/4/90).

19. U.S. Nuclear Regulatory Commission, Instrumentation for Light-Water-Cooled Nuclear Power Plants to Assess Plant and Environs Conditions During and Following an Accident, Regulatory Guide 1.97, December 1980.

20.

IE Bulletin 79-01 B, Environmental Qualification of Class 1E Equipment, Office of Inspection and Enforcement, January 14, 1980 (Supplement 1 dated 2/29/80; Supplement 2 dated 9/30/80; and Supplement 3 dated 10/24/80).

21.

WCAP-1 5338, A Review of Cracking Associated with Weld Deposited Cladding in Operating PWR Plants, Westinghouse Electric Corporation, March 2000.

22. NEI 95-10, Industry Guidance for Implementing the Requirements of 10 CFR Part 54 - The License Renewal Rule, Revision 2, August 2000.

23. NUREG-0588 (Category II),

Interim Staff Position on Environmental Qualification of Safety-related Electrical Equipment, August 1, 1979 Revision 1 11/1/79).

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Docket Nos. 50-280/281 50-338/339 Serial No.: 02-360 Page 1 of 2 License Renewal - Dominion Position on Electrical Fuse Holders Serial No.02-360 Surry and North Anna Power Station, Units 1 and 2 License Renewal Virginia Electric and Power Company (Dominion)

Page 1

Docket Nos. 50-280/281 50-338/339 Serial No.: 02-360 Page 2 of 2 PROPOSED STAFF POSITION ON SCREENING OF ELECTRICAL FUSE HOLDERS On May 16, 2002 the NRC issued, "Proposed Staff Guidance on the Identification and Treatment of Electrical Fuse Holders for License Renewal", to the industry for comment. The proposed staff position is that fuse holders (including fuse clips and fuse blocks) are considered to be passive electrical components and should be included in the aging management review (AMR) process.

As indicated in the proposed guidance stated below, the staff position only applies to fuse holders that are not part of a larger assembly:

"However, fuse holders inside the enclosure of an active component, such as switchgear, power supplies, power inverters, battery

chargers, and circuit

boards, are considered to be piece parts of the larger assembly. Since piece parts and subcomponents in such an enclosure are inspected regularly and maintained as part of the plant's normal maintenance and surveillance activities, they are not subject to AMR."

DOMINION POSITION:

Dominion agrees with the above position that fuse holders are passive, long-lived electrical components within the scope of license renewal and that only those fuse holders that are not part of a larger assembly are subject to an AMR.

Dominion also agrees with the statement in the May 16, 2002 letter that, for the purposes of license renewal, fuse holders/blocks are classified as a specialized type of terminal block because of the similarity in design and construction.

Section 3.6.2 of the License Renewal Application (LRA) provides the aging management review results for cables and connectors which includes terminal blocks and fuse holders. Therefore, there are no additional aging effects that require management.

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