ML17033B591

Redacted Updated Final Safety Analysis Report Chapter 18

ML17033B591
Person / Time
Site:	North Anna
Issue date:	09/29/2016
From:	V Sreenivas Plant Licensing Branch II
To:	Heacock D A Virginia Electric & Power Co (VEPCO)
Sreenivas V, NRR/DORL/LPL2-1, 415-2597
Shared Package
ML17033B477	List: ML17033B480 ML17033B492 ML17033B500 ML17033B509 ML17033B515 ML17033B518 ML17033B525 ML17033B531 ML17033B533 ML17033B540 ML17033B545 ML17033B550 ML17033B570 ML17033B573 ML17033B575 ML17033B583 ML17033B585 ML17033B590 ML17033B591
References
Download: ML17033B591 (48)

Text

North Anna Power Station Updated Final Safety Analysis Report Chapter 18 Intentionally Blank

Intentionally Blank Revision 52-09/29/2016 NAPS UFSAR 18-i18.1NEW AGING MANAGEMENT ACTIVITIES. . . . . . . . . . . . . . . . . . . . . . . . . . .18-118.1.1Buried Piping and Valve Inspection Activities. . . . . . . . . . . . . . . . . . . . . . . . . .18-118.1.2Infrequently Accessed Area Insp ection Activities . . . . . . . . . . . . . . . . . . . . . . .18-218.1.3Tank Inspection Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .18-3 18.1.4Non-EQ Cable Monitoring . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .18-418.2EXISTING AGING MANAGEMENT ACTIVITIES. . . . . . . . . . . . . . . . . . . . . .18-518.2.1Augmented Inspection Activities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .18-618.2.2Battery Rack Inspections. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .18-7 18.2.3Boric Acid Corrosion Surveillance. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .18-718.2.4Chemistry Control Program for Primary Systems . . . . . . . . . . . . . . . . . . . . . . .18-818.2.5Chemistry Control Program for Secondary System s . . . . . . . . . . . . . . . . . . . . .18-918.2.6Civil Engineering Structural Inspection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .18-918.2.7Fire Protection Program . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .18-1018.2.8Fuel Oil Chemistry . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .18-1118.2.9General Condition Monitoring Activities. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

18-1218.2.10Inspection Activities - Load Handling Cranes and Devices. . . . . . . . . . . . . . . .18-1318.2.11Inservice Inspection (ISI) Program - Component and Component Support Inspections. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .18-1318.2.12ISI Program - Containment Inspection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .18-1418.2.13ISI Program - Reactor Vessel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .18-1518.2.14Reactor Vessel Integrity Management . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

18-1618.2.15Reactor Vessel Internals Inspection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

18-1718.2.16Flow Accelerated Corrosion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

18-1818.2.17Service Water System Inspections . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .18-1918.2.18Steam Generator Inspections. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .18-2018.2.19Work Control Process. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .18-2018.2.20Corrective Action System. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .18-2218.3TIME-LIMITED AGING ANALYSIS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

18-2218.3.1Reactor Vessel Neutron Embrittlem ent. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .18-2218.3.1.1Upper Shelf Energy. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .18-2318.3.1.2Pressurized Thermal Shock. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .18-2318.3.1.3Pressure-Temperature Limits. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .18-2318.3.2Metal Fatigue. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

18-24Chapter 18: Programs and Activities That Manage the Effects of AgingTable of ContentsSectionTitle Page Revision 52-09/29/2016 NAPS UFSAR 18-iiChapter 18: Programs and Activities That Manage the Effects of AgingTable of Contents (continued)SectionTitle Page18.3.2.1ASME Boiler and Pressure Vessel Code,Section III, Class 1 . . . . . . . . . . . .18-2418.3.2.2Reactor Vessel Underclad Cracking . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .18-2518.3.2.3ANSI B31.1 Piping . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .18-2518.3.2.4Environmentally Assisted Fatigue. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

18-2518.3.3Environmental Qualification of Electric Equipment. . . . . . . . . . . . . . . . . . . . . .18-2718.3.4Containment Liner Plate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .18-27 18.3.5Plant-Specific Time-Limited Agi ng Analyses . . . . . . . . . . . . . . . . . . . . . . . . . .18-2818.3.5.1Crane Load Cycle Limit . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .18-2818.3.5.2Reactor Coolant Pump Flywheel. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

18-2918.3.5.3Leak-Before-Break . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .18-2918.3.5.4Spent Fuel Pool Liner . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .18-3018.3.5.5Piping Subsurface Indications. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .18-3018.3.5.6Reactor Coolant Pump and ASME Code Case N-481. . . . . . . . . . . . . . . . . . .18-3018.3.6Exemptions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .18-3118.4TLAA SUPPORTING ACTIVITIES. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .18-3118.4.1Environmental Qualification Program . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

18-3118.4.2Transient Cycle Counting . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .18-32

18.5REFERENCES

. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

18-33 Revision 52-09/29/2016 NAPS UFSAR 18-iiiChapter 18: Programs and Activities That Manage the Effects of AgingList of TablesTableTitle PageTable 18-1License Renewal Commitments. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .18-37 Revision 52-09/29/2016 NAPS UFSAR 18-iv Intentionally Blank Revision 52-09/29/2016 NAPS UFSAR 18-1CHAPTER 18PROGRAMS AN D ACTIVITIES THAT MANAGE THE EFFE CTS OF AGING The integrated plant assessment for license renewal identified new and existing aging management programs and activiti es necessary to provide reason able assurance that components within the scope of license renewal will continue to perform their intended functions consistent with the current licensing basi s (CLB) for the period of ex tended operation. The period of extended operation is defined as 20 years from the end of each uni ts original operating license expiration date. This chapter describes these programs and activities and their planned implementation.This chapter also discusses the evaluation result s for each of the plant-specific time-limited aging analyses (TLAAs) performed for license renewal. The evalua tions have demonstrated that the analyses remain valid for th e 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 mana ged for the period of extended operation.

The NRC Safety Evaluati on Report, NUREG-1766, (Reference 24) for the North Anna renewed operation licenses, identi fied commitments as sociated wi th the future development and enhancement of various aging management programs and activities. These commitments are compiled and listed in Appendix D of the NUREG and are provided herein as Table 18-1.18.1 NEW AGING MANAGEMENT ACTIVITIES The following sections provide a description of aging manage ment programs and activities that were not in-place when the renewed operating licen ses were issued for North Anna. These programs and activities were no t part of the licensing basis fo r the original operating license period but were identified as nece ssary to manage aging of various station systems, structures, and components during the period of extended operation.18.1.1Buried Piping and Valve Inspection Activities Prior to the period of extended operation, buried piping and valves will be inspected for the existence of aging ef fects (Item 1, Table 18-1

). The Buried Piping and V alve Inspection Activities will include a one-time inspection of representative samples of pi ping and valves for dif ferent combinations of buried material and burial condition. Visu al inspections will be used to detect cracking of protective coatings and loss of material from protective co atings or the substrate material.

Revision 52-09/29/2016 NAPS UFSAR 18-2The inspection will be completed in accord ance with the schedul e provided in Item 1, Table 18-1, and will include representati ve valves and sample lengths (i.e., several f eet) 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 wra pped with cathodic protection*Stainless steel, coated, and wrapped An engineering evaluation of th e results of the burie d piping and valves in spections will be performed to determine future actions. Corrective acti ons for conditions th at are adverse to quality are performed in accordance with the Corrective Action System. Corrective action provides reasonable assurance th at conditions advers e to quality are promptly corrected.18.1.2Infrequently Accessed Area Inspection Activities The purpose of the Infrequent ly Accessed Area Inspection Activities is to provide reasonable assurance that equi pment and components within th e scope of License Renewal, which are not readily acce ssible, will continue to fulfill their intended functions during the period of extended operation (Item 9, Table 18-1

). A one-time inspection wi ll be performed in accordance with the sche dule provided in Item 9, Table 18-1 , 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 de termined by visual inspection.

These inspections would detect the aging effect of loss of mate rial. In addition, concrete will be inspected to detect the aging effects of loss of material, cracking, and change in material properties (Item 17, Table 18-1

).Infrequently accessed areas de termined to be within the sc ope 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 comp onent supports*Cover for Containment dome plug - Structural condition*Volume control tank cubicle - Structure, supports, and equipment Revision 52-09/29/2016 NAPS UFSAR 18-3*Emergency diesel generator (EDG) exhaust bunkers - Structural condition*Cable spreading rooms, Cable tunnels, Uppe r areas of emer gency switchgear rooms -

Cable raceways and supports**New fuel storage area - Supports and st ructure af fecting spent fuel pool cooling**Auxiliary Building filter and ion excha nger 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**Auxiliary SW expansion joint vault - Supports and piping*

• Charging pump pipe chase - St ructure, supports and piping**Auxiliary feedwater piping tunnel - Structure, supports and piping*

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

Inspection results will be documented for evaluation and re tention. Engin eering evaluation assesses the severity of the visu al inspection results and determines the extent of required actions or future inspections. Corrective actions for conditi ons that are adverse to quality are performed in accordance with the Corrective Action System. Corrective action provides reasonable assurance that conditions adverse to qu ality are promptly corrected.18.1.3Tank Inspection ActivitiesThe purpose of the Tank Inspection Activities is to perform inspections of above ground and under ground tanks to provide reasonable assurance that the tanks will perform their intended function through the period of extended operation (Item 10, Table 18-1

).A one-time inspection will be performed in accordance with the schedule provided in Item 10, Table 18-1 , for specified tanks that are within the scope of license renewal and could Revision 52-09/29/2016 NAPS UFSAR 18-4experience aging effects. The aging ef fect of conc ern for tanks is lo ss of material. A representative sample of tanks wi ll 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 constr uction for the tank, its contents, the foundation upon which the tank is based, and the type of coating. Visual inspecti ons 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:*EDG 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

• Casing cooling tanks*SW pump house air receiver An engineering evalua tion may determine that the obs er ved condition is acceptable or requires repair; or, in the ca se of degraded coatings, may direct remo val of the coating, non-destructive examination of the substrate material, and replacement of the coating.

Re-inspections will be dependen t upon the observed surface condition, and the results of this engineering evaluation. Corrective ac tions for conditions that are a dverse to quality are performed in accordance with the Corrective Action Syst em. Corrective action provides reasonable assurance that conditions adverse to quality are promptly corrected.18.1.4Non-EQ Cable Monitoring The purpose of the Non-EQ Ca ble Monitoring activities is to perform inspections on a limited, but representative, number or accessible cable jackets and connector coverings that are utilized in non-EQ applications (Item 19, Table 18-1

). In order to confirm that ambient conditions are not changing sufficiently to l ead to age-related degradation of the in-scope cable jackets and connector coverings, initial visual inspections for the non-EQ application insulated power cables, Revision 52-09/29/2016 NAPS UFSAR 18-5 instrumentation cables, and cont rol cables (including low-voltage instrumentation and control cables that are sensitive to a reduction in insulation resistance) were performed in accordance with the schedule provided in Item 19, Table 18-1. Visual inspection of the representative samples of non-EQ power, instrumentation, and control cable jackets and c onnector coverings will detect the presence of cracking, discol oration, or bulging, which could indicate aging ef fects requiring management. These effects could be due to high radiation, high temperatur e, or wetted condition environments. Subsequent inspections to confirm ambient conditions are performed at least once per 10 years following the initial inspection. Additionally , a co mmitment for the renewed operating licenses required that upon issuance of NRC staff guidance regarding the aging management of fuse holders in power circuits, the non-EQ cable monitoring program was to be revised to address the guidance (Item 26, Table 18-1

). Guidance was issued by the NRC in Revision 1 to NUREG-1801, Generic Ag ing Lessons Learne d (GALL) Report. North Anna's review of the guidance and the station's electrical equipment conf igurations did not identify any fuse holders requiring aging management.The potentially adverse localiz ed environment due to mois ture which could lead to water-treeing in high- or medium-voltage cables that are within th e scope of license renewal, is also detected by visually monitoring for the pr esence of water around cable

s. Programs utilizing periodic inspections and design f eatures such as drains or sump pumps are used to control the cable localized environment. Cabl e found to be wetted for any significant pe riod 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. Dire ct testing is performed using station procedures to identify age-related degradation in the insulation on the associated cables.Any anomalies resulting from the inspections will be dispositioned by Engineering and will consider the cable environment including the potentia l for moisture in the areas of the anomalies.

Occurrence of an anomaly that is adverse to quality will be entered in to the Corrective Action System. The corrective action proce ss provides reasonable assurance that deficiencies adverse to quality are either prompt ly corrected or are evaluated to be accepta ble. Although age-related degradation is not expected for power, instrumentation, and contro l 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 The following sections provide a description of aging manage ment programs and activities that were essentially in-place when the rene wed operating licenses were issued for North Anna. These programs and activities were part of the li censing basis for the or iginal operating license Revision 52-09/29/2016 NAPS UFSAR 18-6 period. For some programs, howev er , enhancements were identifi ed during the license renewal process as necessary to manage aging of variou s station systems, structures, and components during the period of extended operation.18.2.1Augmented Inspection Activities The purpose of the Augmented Inspection Activitie s is to perform examin ations of selected components and supports in accordance with requirements identified in the Technical Specifications, UFSAR, license commitments, industry opera ting experience, and good practices for the station. Augmented insp ections are outside the requi red scope of ASME Section XI. The scope of Augmented Inspection Ac tivities to be performed dur ing each refueling outage is identified by Engineering in accordance with contro lled procedures. Com ponent conditions are monitored to detect degr adation due to loss of ma terial and cracking. Insp ections include visual, surface, and volumetric examinati ons. The extent of each component inspection is defined within the Augmented Inspection Acti vities program description.

Augmented Inspection Activities include:*High Energy Lines Outside of Cont ainment (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 scope of augmented inspection has been re vised to include the core barrel hold-down spring (Item 3, Table 18-1). The inspection addresses the ag ing ef fect of loss of pre-load. Additionally, the scope for augmented inspections ha s been revised to include an inspection of the pressurizer surge line c onnection (two welds) to the reactor coolant sy stem hot-leg loop piping (Item 2, Table 18-1). The inspections address the aging effe ct of thermal fati gue failure of the weld due to environmental effects, as descri bed in NRC Generic Safe ty Issue (GSI)-190. The scope, frequency, qualifications, a nd methods of inspection are cons istent with those utilized for the Inservice Inspection Program in accordance with ASME Section XI. The initial baseline inspection will occur during the fourth inspec tion interval. Additional inspections will be performed during each subsequent 40-month inspection period. Industry efforts to study the environmental effects on weld th ermal fatigue failure will continue to be evaluated by Dominion.

If warranted, alternatives to this planned inspecti on (re-evaluation, replacemen t, or repair) will be submitted to the NRC for review.

Revision 52-09/29/2016 NAPS UFSAR 18-7 The acceptance standards for non-destructive ex aminations for the Augmented Inspection Activities are consistent with gu idance 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 fo r determination of corrective ac tion. Occurrence of significant degradation that is adverse to quality will be entered into the Co rrective Action System.

Corr ective action provides reasonable assurance that conditions adverse to quality are promptly corrected.18.2.2Battery Rack InspectionsThe 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. Visu al inspections are adequate to identify degr adation of the physical condition of the support racks. These inspections check for corrosion of the support rack structural members.

If any material condition deterior ation 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 reason able assurance that conditions adverse to quality are promptly corrected.18.2.3Boric Acid Corrosion Surveillance Leakage from borated system s creates the potential for degradation of components.

Inspections are performed to pr ovide reasonable assurance that borated water leakage does not lead to undetected loss of ma terial from the reactor coolant pr essure boundary and surrounding components, and ASME Class 1,2, and 3 borated water systems.

Carbon steel is particularly susceptible, but copper alloys, al uminum alloys, inconel alloy base metal and welds, concrete, and certain stainless steel all oys 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 insi de 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. The program was further enhanced based on commitments ma de in response to RAI's from Bulletin 2002-01 (Reference 37). Additional guidance wa s provided in NRC Order EA-03-009, which was then superseded by 10 CFR 50.55.a(g)(6)(ii)(D) (Reference 36), and Bulletin 2003-02 (Reference 38) to inspect the reactor pressure vessel upper an d lower head areas for ev idence of boric acid residue. Similar guidance from the NRC for inspection of Alloy 82/182/600 materials in Revision 52-09/29/2016 NAPS UFSAR 18-8 penetrations and connections on the pres surizer is provided in Bulletin 2004-01 (Reference 39).Borated water systems both inside and outside of Containment are ex amined for evidence of borated water leakage. An over all 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 wa ter leakage through the insulation by examining accessible joints and exposed surfaces of piping and equipment. Components and connections that are not accessible are examined by looking for borated water leakage on th e surrounding area of the floor or adjacent equipment and insulation. Components that are in the vicinity of borated water leakage are also examined for damage resulting from the leakage. In addition, the reactor vessel head, the bottom of the vessel instrument nozzles, and the dissimilar metal welds at specific locations are examined for borated water leakage.

When visual inspections indicate evidence of borated water leakage, the conditi on is entered into the corrective action system. An evaluation is performed to determine if degr adation of the leaking component or nearby affected components has occurred; and whethe r the observed condition is acceptable without repair. Corrective action provides reasonable assurance th at conditions advers e to quality are promptly corrected.18.2.4Chemistry Control Program for Primary SystemsThe purpose of the Chemistry Control Prog ram 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 min imize 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 resu lts are monitored and trended by maintaining logs of measured parameters. Ac ceptability of the measurements is determined by comparison with the limits established in the Chemistry Control Program for Primary Systems. Acceptance criteria for the measured primar y 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 de gradation. Adherence to the guidelines minimizes the aging effects of loss of material and cracking.

Action levels are established to initiate corrective actio n when the es tablished limits are approached or exceeded. Depending on the ma gnitude of the out-of-limit condition, plant shutdown may be performed to minimize aging ef fects 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 acti on provides reasonable as surance that conditions adverse to quality are promptly corrected.

Revision 52-09/29/2016 NAPS UFSAR 18-918.2.5Chemistry Control Program for Secondary SystemsThe purpose of the Chemistry Control Prog ram 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 min imize the loss of material and cracking. The Chemistry Control Program for Secondary System s 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 monitore d and trended by maintaining l ogs of measured parameters.

Acceptability of the measurements is determined by comparison with limits established by the Chemistry Control Program for Secondary Syst ems. Acceptance crite ria for the measured secondary chemistry parameters are listed in the Chemistry Control Program for Secondary Systems. The acceptan ce criteria reflect EPRI guidelines for parame ters 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 actio n when the es tablished 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 wh ile plant actions are being taken. Corrective actions for conditions that are a dverse to quality are performed in accordance with the Corrective Action System. Corrective action provides reasonable assurance that conditi ons adverse to quality are promptly corrected.18.2.6Civil 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 extende d operation, the provisions of the Maintenance Rule Program will be utilized to provide reasonabl e assurance of the continuing capability of civil engineering structures to fulfill their intended functions. The scope of Civil Engineering Structural Inspections has been expa nded to include inspections required for license renewal (Item 4, Table 18-1

). The expanded scope is summ arized in a Dominion report.

Annual monitoring of ground water chemistry, including surveillance sc heduling that accommodates seasonal chemistry variations (Items 16 & 28, Table 18-1), is a commitment that will be implemented in accordance with the schedule provided in Table 18-1. Fulfilling the requirements to perform annual monitoring of groundwater che mistry and account for seasonal variations is accomplished by the implementati on of a periodic testing procedure that is performed quarterly. Having this Chemistry Department periodic te st procedure al ready in place prior to the period of extended operation co mplies with the schedule listed in Table 18-1.

Revision 52-09/29/2016 NAPS UFSAR 18-10Structural monitoring inspections are visual inspectio ns that are performed to assess the overall physical condition of the structure. For concrete struct ures, this includes elastomer sealant materials.

Inspections are performed by tr ained inspectors and include re presentative samples of both the interior and exterior accessible surfaces of structures. Documentation of inspection results includes a general description of observed conditions, lo cation and size of anomalies, and the noted effects of environmental conditions. If an inaccessible ar ea becomes acces sible by such means as dewatering, excavation or installation of radiation shielding, an opportunity will exist for additional inspections. The application for the renewed operating li censes included a commitment for guidance to be provided in plant procedures in accordance with the schedule provided in Item 5, Table 18-1 , to take advantage of such insp ection opportunities when they arise for inaccessible areas. This commitment has been fulfilled through revise d Station procedures.A visual indication of: 1) loss of material for concre te and structural steel, 2) significant cracking for concrete and masonry walls, 3) cracking or change in material prope rties 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 (Item 17, Table 18-1

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

The engineering evaluation of inspection results, including gr oundwater chemistry results, determines whether analysis, repair , or additiona l inspections or testing is required to provide reasonable assurance that structures will continue to fulfill their inte nded functions. Corrective actions for conditions that are a dverse to quality are performed in accordance with the Corrective Action System. Corrective action provides reasonable assurance that conditi ons adverse to quality are promptly corrected.18.2.7Fire Protection Program Regulatory requirements associat ed with fire prot ection systems and im plementation plans are provided in 10 CFR 50.48 and 10 CFR 50, Appendix R. The Fire Protection Plan includes applicable National Fire Protection Association (NFPA) commitme nts 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 do ors, walls, floors, ceilings, pe netration 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/de lamination, heat tran sfer 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 eval uated in the same manner as for any other mechanical system.

Revision 52-09/29/2016 NAPS UFSAR 18-11Testing 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 pressu re boundary for the fire protection syst em, and the availability of water are addressed by routine plant walkdow ns, by pressure/flow tests that are conducted periodically, and by the Work Control Process (Item 30, Table 18-1). 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 (Item 6, Table 18-1

). This task conforms to the requirements of NFPA-25, Section 2-3.1.1. If testin g is performed, re-testing will be performed at 10-year intervals per NFPA-25.Fire protection equipment is examined for i ndications of visible damage. Acceptable sizes for breaks, holes, cracks, gaps, or clearances in fire ba rriers, and acceptable amounts of sealant in penetrations are established in the inspection procedures. Any quest ions regarding the ability of the barrier to fulfill its fire protection func tion are addressed by engineering evaluation. Acceptance criteria for fire prot ection equipment performance tests (i.e., flow and pressure tests) are provided in the appr opriate test procedures. Occurrence of significant degradation that is adverse to quality is entered into the Corre ctive Action System. Corrective action provides reasonable assurance that conditions adverse to quality are promptly corrected.18.2.8Fuel Oil ChemistryThe Fuel Oil Chemistry program manages the loss of material by requiring that oi l quality is compatible with the mate rials of construction in plant systems and equi pment. Poor fuel oil quality could lead either to de gradation of storage tanks or ac cumulations of pa rticulates or biological growth in the tanks. Th e purpose of the Fuel Oil Chemistr y 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 th e operation of safety-related equipment.The Fuel Oil Chemistry program is an agi ng ef fects mitigation act ivity 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 accep tance criteria reflect ASTM guidelines for parameters that have been s hown to contribute to component degradation.

Adherence to the guidelines mitigates the aging effect of loss of material. Parameters analyzed and found to be outside establishe d limits will be repo rted to Engineering, an evaluation will be performed, and appropriate corrective actions will be ta ken. Occurrence of sign ificant deviations that are adverse to quality is entered into the Corrective Action System. Corrective action provides reasonable assurance th at conditions advers e to quality are promptly corrected.

Revision 52-09/29/2016 NAPS UFSAR 18-1218.2.9General Condition Monitoring Activities General Condition Monitori ng Activities are performe d for the assessment and management of aging for components that are loca ted in normally accessible areas. The results of this monitoring are the basis fo r 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 is impleme nted in procedures for engineers and health physics technicians regarding inspection criteria that focus on detection of aging effects during General Condition Monito ring Activities (Item 8, Table 18-1

). An engineering document provides direction for performing plant walkdowns to monitor equipment cond itions. The walkdowns include surveillance activities and observations of maintenance tasks. Indications of age-related degradation are monitored duri ng these walkdowns. Additional in spection information regarding the integrity of components is provided by inspections that s upport the implementation of the Boric Acid Corrosion Control Program. For the he alth physics technician s, procedural guidance exists for performing walkdowns within the Radiological Cont rol Area to moni tor potential pressure-boundary degradation.

The external condition of s upports, piping, doors, and equipm ent will be determined by visual inspection. General Condition Monitoring Activities are perf ormed in three different ways:*Inspections of radiologically contro lled 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 supp orts and doors, as part of General Condition Monitoring ar e procedurally implemented us ing guidance pr ovided in an Engineering document. Doors that require insp ection for age-related degradation also are designated as EQ doors. Monitoring of the EQ doors occurs as directed by the Technical Requirements Manual (Item 7, Table 18-1

). Initial inspections will be completed, using the criteria, in accordance with the schedule provided in Item 7, Table 18-1

.These inspections provide inform ation to manage the aging ef fects 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. Res ponsibility for the evaluation of id entified 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 acti on provides reasonable as surance that conditions adverse to quality are promptly corrected.

Revision 52-09/29/2016 NAPS UFSAR 18-1318.2.10Inspection Activities - Lo ad Handling Cranes and DevicesThe 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 co mponents of these cran es that are subject to aging management review include rails, towers, load trolley steel, fastener s, base plates, and an chorage. An internal inspection of representative secti ons of the box girders for the po lar cranes will be implemented as a one-time only inspection (Item 13, Table 18-1

). This inspection will be performed in accordance with the sche dule provided in Item 13, Table 18-1. An engineering evaluation will determine whether subsequent inspections are required.

The Inspection Activities - Load Handling Cr anes 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 inte grity inspections of applicable cranes which include specific steps to check (visually inspect) the condition of structural members and fasteners on the cranes, the ru nways 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 ac tion can be completed within the scope of the procedure perfor ming the inspection, no additional corrective action may be necessary. Corrective actions fo r conditions that are adverse to quality are performed in accordance with the Corrective Action System. Corrective action provides reasonable assurance that conditions adverse to qu ality are promptly corrected.18.2.11Inservice Inspection (ISI) Pr ogram - 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 Revision 52-09/29/2016 NAPS UFSAR 18-14 Inservice Inspection of Nuclear Power Plant Components. For this program, the license renewal concerns with respect to Subsect ion IWC include only the carbon st eel piping that is susceptible to high ener gy line breaks in the feedwater and main steam systems. Inservice Inspection requirements may be m odified by applicable Relief Requests and Code Cases, which are approved by the NRC specifically fo r each unit. The scope and details of the inspections to be performed are contained in the individualized Inservice Inspec tion Plan for each unit. Each Inservice Inspection Plan is de veloped for a 120-month inspection interval and submitted to the NRC. The examinations required by ASME Section XI utilize visual, su rface, and volumetric inspections to detect loss of ma terial, cracking, gross indications of loss of pre-load, and gross indications of reduction in fracture toughness (which presents itself as cr acking 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 followi ng industry activities related to failure mechanisms for small-bore piping and will eval uate changes to inspection activities based on industry recommendations (Item 11, Table 18-1

). This commitment is closed based on an engineering evaluation indicating that no new industry initiatives have occu rred regarding inspections of small-bore piping. The current ASME requirements remain in ef fect to perform visual inspections of small-bore socket welds, and visual and volumetric inspections of small-bore butt welds.Acceptance standards for inservice insp ections are id entified 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 crit eria set fo rth 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 eith er loss of pre-load or reduction of fracture toughness requires engineering evaluation for determ ination of corrective action. Occurrence of significant degradation that is adverse to quality will be entered into the Corrective Action System. Corrective action provid es reasonable assurance that co nditions adverse to quality are promptly corrected.18.2.12ISI Program - Containment Inspection The ISI Program - Containment Inspection for concrete contai nments and containment steel liners implements the requirements in 10 CFR 50.55a and Subsections IWE and IWL of ASME Section XI. The program incorporates applicable co de cases and approved relief requests. The provisions of 10 CFR 50.55a are invoked for inaccessible areas within the Containment structure.

Revision 52-09/29/2016 NAPS UFSAR 18-15Loss of material is the aging effect for the containment steel liner.

Surface degradation and wall thinning are checked by visual and volumet ric examinations. The frequency and scope of examination requirement s are specified in 10 CFR 50.55a and Subsection IWE. Loss of material, cracking and change in material properties are the aging effects fo r the containment concrete and are checked by visual examinat ions. 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 associ ated with the containment liner and concrete are detected prior to compromising design basis requirements. The ev aluations 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 inspectio ns, anomalous indicatio ns 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 perf ormed for inspection results th at do not meet established acceptance standards. Occu rrence of significant degr adation that is adverse to quality will be entered into the Corrective Action System. Corr ective action provides reas onable assurance that conditions adverse to quality are promptly corrected.18.2.13ISI Program - Reactor VesselThe ISI Program - Reactor Vessel is performed in accordance with the requirements of Subsection IWB of ASME XI, Rules for Inservice Inspect ion of Nuclear Power Plant Components. Inservice Inspection requirements may be modified by applicable Relief Requests and Code Cases, which are approved by the NRC spec ifically for each unit.

The scope and details of the inspections to be performed are contained in the indivi dualized Inservice Inspection Plan for each unit. Each Inservice Inspection Plan is developed and submitted to the NRC for a 120-month inspection interval. A commitment was made for Domi nion to evaluate industry recommendations. and enhance inspections of core support lugs as appropriate (Item 12, Table 18-1). Requests for information from EPRI an d from the Nuclear Energy Institute (NEI) indicate that no updated guidanc e is being developed by the indus try for the insp ection of core support lugs. The continued use of visual inspec tions in accordance with ASME Section XI is proper. Examinations of the core support lugs continue to be performed for NAPS Units 1 and 2 during the 10-year reactor vessel inservice inspections.

In accordance with ASME Sect ion XI, reactor vessel compone nts are inspected using a combination of surface examinations , volumetric examinations, and visual examinations to detect the aging effects of loss of mate rial, cracking, gross i ndications of loss of pre-load, and gross indications of reduction in fracture toughness. Acceptance standa rds 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 indicati ons that are reveal ed by the inservice Revision 52-09/29/2016 NAPS UFSAR 18-16 inspections may require additiona l inspections of similar com ponents, in accordance with Section XI. Evidence of aging effect s requires engineering evalua tion for determination of corrective action. Occurrence of si gnificant degradation that is adve rse to quality is entered into the Corrective Action System. Corrective action pr ovides reasonable assurance that conditions adverse to quality are promptly corrected.18.2.14Reactor Vessel Integrity ManagementThe scope of the Reactor Vess el Integrity Manage ment activities is focused on ensuring adequate fracture toughness of the reactor vessel beltline plate and weld materials. Neutron dosimetry and material properties data derive d from the reactor vessel materials irradiation surveillance program are used in calculations a nd evaluations that demonstrate compliance with applicable regulations. The Reactor Vessel Integrity Management activities includes the following aspects:*Irradiated sample (c apsule) surveillance.*Vessel fast neutron fluence calculations.

• Measurements and calculations of nil-ductility transition temperature (R TNDT) for vessel*beltline materials.*Measurements and calculations of Charpy Upper Shelf Ener gy (C vUSE).*Calculation of reactor coolan t system pressure/temperature (P-T) operating limits, and Low Temperature Overpressure Protection System (LTOPS) setpoints.*Pressurized thermal shock (PTS) screening calculations.Specimen capsules were placed in each of the reactors prior to initial irradiat ion and contain reactor vessel plate and weld mate rial samples. The baseline m echanical properties of reactor vessel steels are determ ined from pre-irradiat ion testing of Charpy V-notch and tensile specimens.

Post-irr adiation testing of similar specimens prov ides a measure of radiation damage. Refer to Section 5.4.3.6.Fast neutron irradiation is the cause of radiati on damage to the reacto r vessel beltline. The results of surveillance capsule dosimetry analyses are used as benchmarks for calculations of neutron fluence to the surv eillance capsules and to th e reactor vessel beltline.Measured values of Charpy transition temperature and C v USE are obtained from mechanical testing of irradiation surveillance program specimens. Measured values of transition temperature are used to determine the referen ce temperature for nil-ductility transition (RT NDT) for the limiting reactor vessel beltline material. RTNDT is a key analysis input for the determination of reactor coolant system P-T operating limits and LTOPS setpoints. Measured Revision 52-09/29/2016 NAPS UFSAR 18-17values of transition temperature sh ift are similarly utilized in PTS screening calcul ations required by 10 CFR 50.61. Measured values of C v USE are used to verify compliance with the upper shelf energy requirements of 10 CFR 50 Appendix G.Acceptable values are establishe d for the following parameters:*Heatup and cooldown li mits, as implemented by T echni cal Specifications, to ensure reactor vessel integrity.*A PTS reference temperature that is within the screening criteria of 10 CFR 50.61.*A fast fluence value for the surveillance cap sule that bounds the expected fluence at the af fected vessel beltline material through the pe riod of extended operation.

• C v USE greater than limits set forth in 10 CFR 50, Appendix G.Based on established parameters, calculations ar e pe rformed to ensure that the units will remain within the acceptable values.18.2.15Reactor Vessel Internals InspectionVisual inservice inspections are im plemented in accord ance with Category B-N-3 (Removable Core Support Stru ctures) 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 submit ted to the NRC. The scope of components that comprise the reactor intern als includes the upper and lower core internals assemblies. This includes core support and hold-dow n spring components, as well as, the baffle/former bolting and barrel/former bolting.Visual inspections are utilized to detect loss of material an d 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 perfor med with the internals assemblies removed from the reactor vessel.Acceptance standards for Reactor Vessel Inte rnals Inspection activitie s 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 degr adation requires engine ering evaluation for determination of corrective action.

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

Revision 52-09/29/2016 NAPS UFSAR 18-18Dominion has and will continue to remain active in indu stry groups, including the EPRI-sponsored Material Reliability Project In dustry 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 (Item 14, Table 18-1). Dominion committed to perform a one-time focused inspection of the reactor vessel internals on the most susceptible si ngle unit between North Anna and Surry, in accordance with the schedule provided in Item 14, Table 18-1. The results of the one-time inspection would be evalua ted to determine if additional inspections were required. The most susceptible single unit was de termined to be Surry Unit 1, w ith the exception of the co ntrol rod guide cards. It was determined that Surry Unit 2 contained the more su sceptible control rod guide cards. Following the approval of License Renewal fo r Surry and North Anna (NUREG-1766), MRP-227-A, "Materials Reliability Program: Pressurized Water Reactor Internals Inspection and Evaluation Guidelines,"

introduced additional inspection requirements for reactor vessel internals susceptible to aging effects. Both Surry Unit s 1 and 2 have completed inspections under MRP-227 guidance, thus satisfying the co mmitment to perf orm a one-time inspection on the most suscepti ble unit. Dominion plans to implement reactor vessel internals inspections on North Anna Units 1 and 2 under th e guidance of MRP-227-A.18.2.16Flow Accelerated CorrosionThe purpose of the Flow Accelerated Corrosion program is to identify, inspect, and trend components that are susceptible to the aging effe ct 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 accordan ce with NRC Generic Letter 89-08, Erosion/Corrosion-Induced Pipe W all Thinning (Reference 15), and NUREG-1344, Erosion/Co rrosion-Induced Pipe W all Thinning in U.S. Nuclear Power Plants (Reference 16), and EPRI Guideline NSAC-202L, Rev 4 Recommendations for an Effective Flow Accelerated Corrosion Program (Reference 17).The scope of the Flow Acceler ated Corrosion program includes portions of the feedwater systems, the main and auxili ary steam systems, and the st eam generator blowdown lines.The Flow Accelerated Corrosion program also includes susceptible vent and drain lines.

The identification of components and piping segments to be inclu ded in each Flow Accelerated Corrosion effort is performed by Engineering usi ng 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 inspectio ns 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 whet her flow-accelerated degradation is occurring.

Revision 52-09/29/2016 NAPS UFSAR 18-19 The decision to repair or replace a component is made by Engineering. For the internal surface examinations, engi neering evaluations are utilized to determine whether the results of visual inspections indicat e conditions that require correctiv e action. Occurrences of significant degradation that are adverse to quality are entered into the Corr ective Action System. Corrective action provides reasonable assura nce that conditions adverse to quality are promptly corrected.18.2.17Service Water System Inspections Compliance with Generic Letter 89-13 (Reference 18) requires a variety of inspections, non-destructive examinati ons, and heat transfer testing for components cooled by service water. Generic Letter 89-13 directed utilities to assess the following aspe cts of operational problems with service water cooling systems:*Biofouling*Heat Transfer Testing*Routine Inspection and Maintenance*Single-failure Walkdown

• Procedure ReviewThe SW System Inspections program provides reasonable assurance that corrosion (including microbiologically-inf luenced corrosion, MIC), eros ion, protective coating failure, silting, and biofouling of service water piping and components will not caus e 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 SW system piping and co mponents that could adversely af fect performance. Preventive maintenance, inspection, and repa ir procedures have been de veloped to provide reasonable assurance that any adverse ef fect s of exposure to serv ice water are adequate ly addressed. The addition of biocide to the SW sy stem reduces biological growth (including MI C) that could lead to degradation of components exposed to the service water. Additionally, a one-time measurement of sludge buildup in the SW rese rvoir will be performed (Item 23, Table 18-1). This measurement will be completed in accordance wi th the schedule provided in Item 23, Table 18-1

.SW System Inspections are performed to check for biofouling, damaged coatings, and degraded material condition. Heat transfer parameters for compone nts cooled by service water are monitored. Visual inspections are pe rformed to check for loss of ma terial 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.

Revision 52-09/29/2016 NAPS UFSAR 18-20The acceptance criteria for visual inspections are identified in the procedures that perform the individual inspections. The procedures identif y the type and degree of anomalous conditions that are signs of degradation. In the case of service water, degrad ation includes biof ouling as well as material degradation. Engin eering evaluations determine whet her observed dete rioration of material condition is sufficiently extensive to lead to loss of intended function for components exposed to the service water. An engineering ev aluation will also determin e if additional sludge measurements in the SW reservoir are needed. Th e 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 Corre ctive Action System. Corrective action provides reasonable assurance that conditions adverse to quality are promptly corrected.18.2.18Steam Generator InspectionsSteam Generator Inspections ar e performed in accordance with Technical Specifications and Inservice Inspection requi rements of ASME Section XI. Steam Generator Inspections plans are based upon the guidelines established by Nuclear Ener gy In stitute document, NEI 97-06 (Reference 4) and the Electric Power Re search Institute steam gene rator inspection guidelines (Reference 5). Steam generator tubing in s pections are performed on a sampling basis. The sample population inspected meets or exceeds the requir ements of T echnical Specifications. Qualified techniques, equipment and personne l are used for inspections in accordance with site-specific eddy current analysis guidelines.

Examination of steam generato r sub-components other than t ubes are performed as required by the gove rning edition and addenda of ASME Section XI, as imposed by 10 CFR 50.55a. In some cases the specific inspecti on requirements of ASME Section XI are modified by regulatory commitments and approved Relief Re quests. Inspections of the steam generators to check for loss of material, cracking, and gross i ndications of loss of pre-load in clude a combination of visual inspections, surface examinati ons, and volumetric examinations. Tubing inspections are performed in accordance with ASME Section XI, Subsection IWB.Acceptance standards for steam generator in spections are provided in ASME Section XI, Subsections IWB-3500 and IWC-3500. Evidence of component de gradation requires engineering evaluation for determination of co rrective action. Occurrence of si gnificant 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.18.2.19Work Control Process Performance testing and maintenance activities, both preventive and co rrective, are plan ned and conducted in accordance with the station's Wo rk Control Process. The Work Control Process integrates and coordinates the combined efforts of Maintenance, Engineering, Operations, and other support organizations to ma nage maintenance and testing ac tivities. Performance testing on heat exchangers evaluates the heat transfer capability of the co mponents to determine if heat Revision 52-09/29/2016 NAPS UFSAR 18-21 transfer degradation is occurring. Maintenance activ ities provide opportuniti es for inspectors who are Visual Test (VT) qualified to visually inspect the surfaces (internal and external) of plant components and adjacent piping (Item 21, Table 18-1

). Adjacent piping is primarily the internal piping surfaces i mmediately adja cent to a system component th at is accessib le through the component for visual inspection. Visual inspec tions 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.The application for the renewe d operating licenses included a co mmitment to have changes made in procedures to reasonabl y assure that consistent inspec tions of components are completed during the process of performing work control process activities (Item 15, Table 18-1

). Implementation of consistent insp ections is accomplished using au tomated inspection instructions for work orders involving component s and structures that have b een identified as requiring aging management. The instructions co nsistently require inspections to identify a variety of aging mechanisms required for the renewed operating licenses.The Work Control Process also provides oppor tunities through preventive maintenance sampling (predictive analysis) to collect lubricating oil and engine coolant samples for subsequent analysis of contaminants that would provide early indi cation of an adverse environment that can lead to material degradation.

The inspections, testing, and sampling perfor med under the W ork 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 (Item 18, Table 18-1). The change in material properties is specifically required to be m onitored for elastomeric sealan ts. This monitoring occurs during the periodic Maintenance Rule visual in spections of structur es, and during routine inspections performed for ma intenance activities. These inspection and maintenance activities are scheduled through the work control process.

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.

Revision 52-09/29/2016 NAPS UFSAR 18-22Whenever evidence of aging effects exists, an engineering evalua tion is performed to determine whether the observed c ondition is acceptable w ithout repair. Occurren ce of significant aging effects that is adverse to quality is en tered 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 Pr ocess will be used to ensure that locations with similar material and envi ronmental conditions are inspected as directed by a Station procedure (Item 29, Table 18-1

).As confirmation that the Work Control Proce ss 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 pe rformed will be performed and, if Work Control Process activities ar e found not to be represen tative, supplemental inspect ions will be performed (Item 22, Table 18-1). Two audits of the Work Control Pr ocess are anticipated, and each will consist of a review of the previous 10 years of historical data. These audits will be performed in accordance with the schedule provided in Item 22, Table 18-1. Any required supplemental inspections would be completed within 5 years after the audits are performed.18.2.20Corrective Action System The Corrective Action System is a required element of the Quality As surance Program outlined in the Quality Assurance Topical Report (Chapter 17 of the Updated Final Safety Analysis Report). The Qualit y Assurance Program implemen ts the requirements of 10 CFR 50, Appendix B, and is consistent with the summary in Section A.2 of NUREG-1800, Standard Review Plan for License Renewal. The Corrective Action System activities include the elements of corrective action, confirmation process, and administrative cont rols; and is applicable to the safety-related and non-safety-relate d structures, systems, and co mponents that are within the scope of license renewal.

18.3 TIME-LIMITED AGING ANALYSISAs part of the applicatio n for a renewed license, 10 CFR 54.21(c) requires that an evaluation of TLAAs for the period of extended operation be provided. The following TLAAs have been identified and evaluated to meet this requirement.18.3.1Reactor Vessel Neutron EmbrittlementThe reactor vessel is subjected to neutron irradiation from the core. This irradiation results in the embrittlement of the reactor vessel materials. Analyses ha ve been performe d that address the following:*Upper shelf energy*PTS Revision 52-09/29/2016 NAPS UFSAR 18-23*RCS P-T 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 C v USE of reactor vessel beltline materials to meet Appendix G requirements. If the USE of a reactor vessel beltline materi al is predicted to not meet Appendix G requirements, then licensees must submit an analys is that demonstrates an equivalent margin of safety at least three years prio r to the time the material is predicted to not meet those requirements.

Reactor vessel calculations have been performed which de monstrated that the upper shelf energy values of limiting r eactor vessel beltline materials at th e end of the period of extended operation meet Appendix G requirements. Thus, the TLAA has b een 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 ve ssel integrity, known as 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 inte grity 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 embrit tlement, and the presence of a critical-size defect in the vessel wall.The reference temperature for pressurized thermal shock (RT PTS) is defined in 10 CFR 50.61. RT PTS values for the limiting reactor vessel ma terials at the end of the period of extended operation have been r ecalculated by Dominion.

At the end of the period of extended operation, the calculated RT PTS values for the beltline material s 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 LimitsAtomic 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, er ected, 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.

Revision 52-09/29/2016 NAPS UFSAR 18-24Reactor 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 (RTNDT), and to calculate reactor co olant system (RCS) P-T operating limits valid through the end of a period of extended operation. Maximum allowable LTOPS power-operated relief valve 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 limit s in order to maintain compliance with the governin g requirements of 10 CFR 50 Appendix G.The TLAA has been projected to the end of the period of ex tended operation and is found to be adequate.18.3.2Metal Fatigue The thermal fatigue analyses of the station' s mechanical com ponents have been identified as TLAA.

18.3.2.1 ASME Boiler and Pressure Vessel Code,Section III, Class 1The steam generators, pressurizers, reactor ve ssels, 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 Pre ssure 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 tran sients used to analyze the ASME III requirements are often very conservative. Design transient magnit ude and frequency are more severe than those occurring during plant operation. The magnitude and number of the actu al 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 intend ed functions for the period of extended operation. A cycle counting program (Section 18.4.2) is in place to provide reasona ble 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, re actor vessels, reactor coolant pumps, CRDMs, a nd all RCS pressure boundary pipi ng have been evaluated and determined to remain valid for the period of extended operation.

Fatigue analyses for the reacto r 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.

Revision 52-09/29/2016 NAPS UFSAR 18-25 18.3.2.2 Reactor Vessel Underclad Cracking In early 1971, an anomaly was id entified in the heat-affected zone of th e 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 mechan ics evaluation based on a representative set of design transients. The occurrences were extrapolated to cover 60 years of service life. This 60-year eval uation shows insignificant growth of the underclad cracks and is documented in WCAP-15338 (Reference 21). The plant-specific desi gn 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 PipingThe 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 numb er of anticipated cycles is limited to 7000 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 7000 cycles. Considering this limitation , a review of the ANSI B31.1 piping within the scope of license renewal has been performed to iden tify those systems that operate at elevated temperature and to establish their cyclic ope rating practices. Under cu rrent plant operating pr actices, piping systems within the scope of licen se renewal are only occas ionally subject to cyclic operation. Typically, these systems are subjec ted to continuous stea dy-state operation.

Significant variation in operating temperatures occur onl y during plant heatup and cooldow n, during plant transients, or during periodic testing.

The analyses associated with ANSI B31.1 piping fatigue ha ve been evaluated and determined to remain valid for the period of extended operation excep t for sample lines for the hot and cold legs. The analyses associated with samp le 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 GSI-190 (Reference 6) identifies a NRC staff concern a bout the ef fects 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 CLB. As a result, th e criterion specified in 10 CFR 54.3(a)(6) is not satisfied. Hence, Revision 52-09/29/2016 NAPS UFSAR 18-26environmental 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-190, the NRC has concluded that licensees who apply for licen se renewal should address the effects of coolant environment on component fatig ue 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 desi gn limits are not exceeded. Secondly, the reactor water's environmental effects on fatigue life we re evaluated using the most recent data from laboratory simulation of the reactor coolant environment.As a part of the industry effort to address environmental ef fects 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 St eam Supply System vendors. The pressurized water reactor calculations, es pecially the early-vintage Westinghous e pressurized water reactor (PWR) calculations, are directly relevant to the Dominion stations. The description of the "Older Vintage Westinghouse Plant" eval uated in NUREG/CR-6260 applies to the North Anna station. In addition, the transient cy cles considered in the evaluation match or bound the design. The results of NUREG/CR-6260 analyses, and ad ditional 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 fatig ue-sensitive locations to account for environmental ef fects.Based on these adjusted CUFs (using the environm ental fatigue penalty fa ctor), it has been determined that the sur ge line connection at the reactor coolant system's hot leg pipe exceeds the design threshold of 1.0. As a consequence, management of environmentally assisted fatigue is required. Additionally, the CUFs that were adjusted for environmental effects for the safety injection (SI) and chargi ng line nozzles initially were determined to exceed the design threshold of 1.0. Subsequent fatigue evaluations (Reference 35), using the methodology of ASME Section III, NB-3200, confirm that the CUFs for the SI and char ging line nozzles do not exceed the ASME Code allowable value of 1.0, including the effects of the reactor water environment. Therefore, the SI and charging line nozzles will not require enhanced inspections for the management of environmenta lly assisted fatigue (Item 25, Table 18-1

).The approach to manage environmentally assist ed fatigue for the surge line is developed from one or more of the followi ng options and submitted to the NRC for review prior to the period of extended operation (Item 24, Table 18-1

):1.Further refinement of the fatigue analysis (e.g., NB-3200 analysis) to lower the CUFs to below 1.0, or Revision 52-09/29/2016 NAPS UFSAR 18-272.Repair of the affected locations, or3.Replacement of the affected locations, or4.Inspection of the affected locations.The surge line weld at the hot le g pipe connection is included (Item 2, Table 18-1) as an Augmented Inspection Activity (Section 18.2.1). Baseline inspections of the sur ge line welds are planned prior to entry into the period of extende d operation. Inspections wi ll also occur once per 40-month ISI period, ther eafter. The results of these inspections and the resu lts of planned research by the EPRI-sponsored Materials Reliability Program wi ll be utilized to assess the appropriate approach for addressing environmentally assisted fatigue of the surge lines during the period of extended operation.

The use of inspections (Option

4) to manage environmentally assisted fatigue during the period of extended operation, require s inspection details such as scope, qualification, method, and frequency be provided to the NR C for review prior to entering the period of extended operation.

The NRC review ensures that the inspection interv als for the periodic inspection of the affected locations would be determined by a method accepted by the NR C. Dominion Letter No.14-285 provides the required pressurizer surge li ne weld inspection summary to the NRC.

Implementation of one or more of the above listed options ensu res that the potential effects of the reactor water environment have been addressed for the period of extended operation as required by GSI-190.18.3.3Environmental Qualificatio n of Electric Equipment 10 CFR 54.49 requires that each holder of a nuclear power plant operating license establish a program for qualifying sa fety-related electric equipment. Su ch a program has b een implemented at the station and is invoked by Administrative Procedure. An alyses and tests that qualify safety-related equipment for the period of extended operation are considered TLAAs.The Environmental Qualif ication (EQ) Program (Section 18.4.1) requires that all electrical equipment important to safety located in a ha rsh environment shall be managed through the period of extended operation.

18.3.4Containment Liner PlateThe accumulated fatigue effects of applicable liner loading conditions were evaluated in accordance with Paragraph N-415 of the ASME Boiler and Pr essure Vessel Code,Section III, 1968. The evaluation was based on 1000 cycles of operating pr essure variations, 4000 cycles of operating temperature variations, and 20 design earthquake cycles. The operating pressure variatio ns are anticipate d to be less than 100 and temperature variations ar e anticipated to be less than 400 for forty years of opera tion. Extrapolatin g these anticipated values for sixty years of operation results in 150 pressure variations and 600 temperature variations (Reference Revision 52-09/29/2016 NAPS UFSAR 18-28Table 3.8-7). The number of design cycles was conservatively increased to 1500 cycles of operating pressure variations, 6000 cycles of operating temp erature variation, and 30 design earthquake cycles by using a multip lication factor of 1.5, to acco unt for the period of extended operation.A review of the identified cal culations has determin ed that the increase in the number of cycles due to the period of ex tended 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 operati ng period as currently designed. The analyses associated with th e Containment liner plate have b een revised and projected to be valid for the period of extended operation.18.3.5Plant-Specific Time-L imited Aging Analyses 18.3.5.1 Crane Load Cycle Limit The following are cranes included in li cense 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 overh ead handling systems meet the intent of Crane Manufacturers Association of America, Inc. (CMAA) Specification

1. 70. The crane load cycle provided in CMAA-70 has been identified as a TLAA, with the mo st 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 us ed to load new fuel into the fuel pool, to perform the various rearrangements required by operations support, to accommodate in spections by fuel vendors, and to load spent fuel casks. In such service, the cran e is conservatively expected to make a total of 50,000 half-load lifts in a 60-year period.Therefore, the analyses associ ated with crane design, incl ud ing fatigue, are valid for the period of extended operation.

Revision 52-09/29/2016 NAPS UFSAR 18-29 18.3.5.2 Reactor Coolant Pump Flywheel During normal operation, the reactor coolant pum p flywheel possesses sufficient kinetic energy to produce high-energy missiles in the unlikely event of failure.The aging effect of concern is fatigue crack initiat ion in the flywheel bore keyway. An evaluation of a failure over the period of extended operation has be en 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 th e 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-BreakWestinghouse (Westinghouse Owners Group) te sted and analyzed crack growth wi th 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-en ded 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 evalua tion was, that, under the worst co mbination of loading, including the effects of safe shutdown earthquake, the cr ack 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 pipi ng breaks in reactor coolant sy stem primary loop piping has been termed "leak-before-break" (LBB).In 1986, Westinghouse performed an LBB analys is of the primary loop piping. Two TLAAs related to LBB have been identi fied: fatigue crack growth and th ermal aging of cast austenitic stainless steel. The original fatigue crack grow th 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 has continued to participate in the ongoing NRC/indus try program on Alloy 82/182-weld material and implemented the findings/r esolution from this ef fort, as appropriate (Item 20, Table 18-1

). The guidance of MRP-126, "Materials Reliabil ity Program: Generic Guidance for Alloy 600 Management", has been used as the basi s for a Dominion Program to manage aging for Inconel alloy welds.

Revision 52-09/29/2016 NAPS UFSAR 18-30To 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 vali d 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 calculati on has been identified which docum ents that the spent fuel pool design meets the general industry criteria. The calculation include s a fatigue anal ysis 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 exp ected 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 identi fied that addressed piping subs urface indications detected by inspections, performed in acc ordance with ASME Section XI. Section XI provides the acceptance criteria for various flaw orient ations, locations and si zes. 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 cy cles experienced by the piping will not exceed these values for sixty years of operation, the anal yses have been determin ed to remain valid for the period of extended operation.

18.3.5.6 Reactor Coolant Pump and ASME Code Case N-481 Periodic volumetric inspectio ns of the welds in the prima ry loop pump casings in commercial nuclear power plan ts were required by Section XI of the ASME Boiler and Pressure Vessel Code. Since the reactor coolant pump casings were insp ected prior to being placed in service, and no significant mechanisms exist for crack initiation a nd propagation; it was concluded that the inservice volum etric inspection could be replaced with an acceptable alternate inspection. In recognition of th is conclusion, ASME Code Case N-481, Alternative Examination Requirements for Cast Au stenitic Pump Casings, provided an alternat ive to the volumetric inspection requirement. The code case allowed the replacement of volumetric examinations of primary loop pump casings with fracture mechanics base d integrity evaluations - Item (d) of the Revision 52-09/29/2016 NAPS UFSAR 18-31code case - supplemented by specific visual ex aminations. 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 be en projected to be valid for 60 years. The 2000 Addenda of ASME Section XI removed the volumetric examination of the reactor coolan t pump casing welds. Starting with the fourth inspection interv al the Code Case is no longer needed.18.3.6Exemptions The requirements of 10 CFR 54.21(c) stipulate that the appl ication for a renewed license should include a list of plant-specif ic exemptions granted pursuant to 10 CFR 50.12 and that are based on TLAA, 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 TLAA. No pl ant-specific exemptions granted pursuant to 10 CFR 50.12 and based on a TLAA as defined in 10 CFR 54.3 have been identified.

18.4 TLAA SUPPORTING ACTIVITIES18.4.1Environmental Qualification Program The EQ Program activities are in comp liance with the requirements of 10 CFR 50.49. The EQ Program will be c ontinued throughout the period of exte nded operation. Electrical equipment located in a harsh environment is evaluated for environm ental qualification if they are required to function in the conditions that will exist post-accident after being subjected to the normal ef fects of aging. A harsh envi ronment results from a 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 app licable to the followi ng 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 electrica l equipment whose failure, under postulated environmental conditions, could prevent accomplishment of safety functions*Certain post-accident monitoring equipm ent as described in Regulatory Guide 1.97 (Reference 19).Guidance regarding environmental qu alification 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 Qualificat ion Master List provide s a listing of electrica l equipment that is important to safety and is located in a potentially harsh environment.

Revision 52-09/29/2016 NAPS UFSAR 18-32 Based on the definitions of 10 CFR 54, certain EQ calculations ar e considered to be 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, oriii.The effects of aging will be adequately managed during th e 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 rene wal 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 quali fication 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 wh en subjected to various postulated environmen tal conditions. These conditions include expected ranges of temperature, pressure, humidity, ra diation, 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, ac ceptance criteria an d corrective actions.

Qualification Document Review s (QDRs) provide the basis fo r qualifying EQ components.

The QDRs provide the following information for each piece of equipment that is qualified:*The performance characteri stics required under normal, DB E, and post-DBE conditions.*The voltage, frequency, load, and other elec trical characteristics for which equipment performance can be provided with reasonable assurance.*The environmental conditions , including temperature, pre ssure, humidity , radiation, chemical spray, and submergence, at the location where the equipment must function.18.4.2Transient Cycle Counting During normal, upset, and te st conditions; reactor coolant system pressure boundary components are subjected to tran sient 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 co mponents have been designe d to withstand a number of design transients without experien cing fatigue failures during thei r operating life. The purpose of the Transient Cycle Counting is to record the num ber of normal, upset, and test events, and their sequence that the station experi ences during operation. De sign transients are counted to provide reasonable assurance that plant operation doe s not occur outside th e design assumptions.

Revision 52-09/29/2016 NAPS UFSAR 18-33The Transient Cycle Counting activities are ap plicable to the reac tor 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 < 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 SI*Normal charging and let down return to service*Charging trip with delayed return to serviceThe aging effect that is managed by counti ng transient cycles is cracking due to metal fatigue. The T ransient Cycle Counting activities monitor transient cycles that have been experienced by each unit and comp are the actual numbe r of cycles to a design assumption. Any concerns related to fatigue are mitigated, as long as th e number and magnitude of transient cycles are less than the design assumptions. Approaching a design limit may indicat e 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 fact or has not been exceeded. If warranted, component repair or replacement would be initiated.

18.5 REFERENCES

1.Working Draft of the NRC Standard Review Plan for the Review of License Renewal Applications for Nu clear Power Plants.2.Generic Letter 88-05, Boric Acid Corr osion of Carbon Steel Reactor Pressure Boundary Components in PWR Plants , March 17, 1988.

Revision 52-09/29/2016 NAPS UFSAR 18-343.NUREG-0800, Standard Review Plan for the Review of Safety Analysis Re ports for Nuclear Power Plants - LWR Edition , US Nuclear Regulatory Commission. (Formerly NUREG-75/087)4.NEI 97-06, Steam Generator Program Guidelines , Revision 2, Nuclear Energy Institute.5.PWR Steam Generator Examination Guidelines, Revision 7, Electric Power Research Institute.6.Generic Safety Issue (GSI)-190, Fatigue Evaluation for Metal Components for 60-year Plant Life , U.S. Nuclear Regulat ory Commission, August 1996.7.Memorandum from Ashok C. Thadani, to Wi lliam 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 Interi m Fatigue Curves to Selected Nuclear Power Plant Components , U.S. Nuclear Regulat ory 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, Contr ol of Heavy Loads at Nuclear Power Plants , U.S. Nuclear Regulatory Commission, July 1980.12.WCAP-14535A, T opical Report On Reactor Coolant Pu mp Flywheel Inspection Elimination , Westinghouse Electric Corporation, November 1996.13.American National Sta ndards Institute: ANSI B30.2-1976, Over head and Gantry Cranes.14.American National Sta ndards Institute: ANSI B30.11-1973, Monorail Systems and Under hung Cranes.15.Generic Letter 89-08, Erosion/Corrosion-Induced Pipe Wall Thinning , May 2, 1989.16.NUREG-1344, Erosion/Corrosion-Induced Pipe Wall Thinning in US Nuclear Power Plants , April 1, 1989.17.NSAC-202L, Revision 4, Recommendation for an Effective Flow Accelerated Corr osion Program, Electric power Research Institute.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.

Revision 52-09/29/2016 NAPS UFSAR 18-3520.IE Bulletin 79-01B, Envir onmental Qualification of Class 1E Equipment , Of fice 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-15338, A Review of Cracking Asso ciated with Weld Deposit ed Cladding in Operating PWR Plants, Westinghouse Electric Corporation, March 2000.22.NEI 95-10, Industry Guidance for Implemen ting 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 dated 11/1/79).24.NUREG-1766, Safety Evaluation Report Rela ted to the License Renewal of North Anna Power Station, Units 1 and 2, and Surry Power Station Units 1 and 2, December 200225.Letter from Leslie N. Hartz (Dominion) to NRC, Dominion Position Regard Fuse Holders, Serial No.02-691, November 4, 2002.26.Letter from Eugene S. Grec heck (Dominion) to NRC, Suppl emental Information to Support License Renewal, Serial No.02-706, December 2, 2002.27.Letter from David A. Christ ian (Dominion) to NRC, Requ est for Add itional Information License Renewal Applications, Serial No.01-686, January 16, 2002.28.Letter from David A. Christ ian (Dominion) to NRC, Requ est for Add itional Information License Renewal Applications, Serial No.02-163, May 22, 2002.29.Letter from David A. Christ ian (Dominion) to NRC, Requ est for Add itional Information License Renewal Applications, Serial No.01-685, January 4, 2002.30.Letter from David A. Christ ian (Dominion) to NRC, Requ est for Add itional Information License Renewal Applications, Serial No.01-647, November 30, 2001.31.Letter from David A. Christ ian (Dominion) to NRC, Requ est for Add itional Information License Renewal Applications, Serial No.01-514, September 27, 2001.32.Letter from David A. Christ ian (Dominion) to NRC, Requ est for Add itional Information License Renewal Applications, Serial No.01-732, February 5, 2002.33.Letter from David A. Chri stian (Dominion) to NRC, License Rene wal Applications -

Submittal, Serial No.01-282, May 29, 2001.34.Letter from Leslie N. Hartz (Dominion) to NRC, Request fo r Additional Information License Renewal Applications, Serial No.

02-332A, October 1, 2002.35.Letter from Leslie N. Hartz (Dominion) to NRC, Engineeri ng Evaluation Results and Closure of Commitments for Management of Environmentally-Assisted Fatigue in Accumulator and Charging Nozzles, Serial No.03-616, January 6, 2004.

Revision 52-09/29/2016 NAPS UFSAR 18-3636.10 CFR 50.55a, Codes and Standards.37.Bulletin 2002-01, Reactor Pressure Vessel Heal Degr adation and Reactor Coolant Pressure Boundary Integrity , Nuclear Regulatory Commission, Washington, D.C.38.Bulletin 2003-02, Leakage from Reactor Pressure Vessel Lower Head Penetrations and Reactor Coolant Pressure Boundary Integrity , Nuclear Regulatory Commission, Washington, D.C.39.Bulletin 2004-01, Inspection of Alloy 82/182/600 Materials Used in the Fabrication of Pressurizer Penetrations and Steam Space Piping Connections at Pressurized-Water Reactors, Nuclear Regulatory Commission, Washington, D.C.

Revision 52-09/29/2016 NAPS UFSAR 18-37Table 18-1 LICENSE RENEWAL COMMITMENTSItem Commitment Schedule a Source Ref.1.Develop and implement inspection program for buried piping and valves.

One-time between years 30-40.Additional inspections

based on results.Table B4.0 b , RAI B2.1.1-1 33 31 2.Add pressurizer surge line to Augmented Inspection Program.Prior to Period of Extended Operation (Complete)Table B4.0, RAI 4.3-7 33 27 3.Add core barrel hold-down spring to Augmented Inspection Program.

Prior to Period of Extended Operation (Complete)Table B4.0 33 4.Expand scope of Civil Engineering Structural Inspection to cover License Renewal requirements.

Prior to Period of Extended Operation (Complete)Table B4.0 33 5.Revise plant documents to use inspection opportunities when inacces sible areas become accessible during work activities.

Prior to Period of Extended

Operation (Complete)Table B4.0 33 6.Incorporate NFPA-25, Section 2-3.1.1 for sprinklers.Prior to year

50. If testing

used, repeat every 10 years.Table B4.0 33 7.Develop inspection criteria for

non-ASME supports and doors.Prior to Period of Extended Operation (Complete)Table B4.0 33 8.Develop procedural guidance for inspection criteria that puts focus on aging effects.

Prior to Period of Extended

Operation (Complete)Table B4.0 33 9.Develop and implement

inspection program for infrequently accessed areas.

One-time between years 30-40. Additional inspections based on results.Table B4.0, RAI 3.5-1, RAI 3.5.8-1 33 30 32a.The Period of Extended operation is the period of 20 years beyond the expiration date of each unit's original operating license. For North Anna Unit 1, the Period of Extended Operation is from April 2, 2018 to April 1, 2038 and for North Anna Unit 2, from August 22, 2020 to August 21, 2040.b.Table B4.0 is the table of Licensee Followup Actions located in the License Renewal Application for North Anna (Reference 33).

Revision 52-09/29/2016 NAPS UFSAR 18-38 10.Develop and implement inspection program for tanks.

One-time between years

30-40. Additional inspections based on results.Table B4.0 3311.Follow industry activities

related to failure mechanisms for small-bore piping. Evaluate changes to inspection activities

based on industry recommendations.

On-going activity (Complete)Table B4.0, RAI 3.1.1.2-2 33 30 12.Follow industry activities related to core support lugs.

Evaluate need to enhance

inspection activities based on industry recommendations.

On-going activity (Complete)Table B4.0 33 13.Inspect representative sections

of polar crane box girders.

One-time between years

30-40. Additional inspections based on results.Table B4.0 33 14.Follow industry activities

related to reactor vessel internals issues such as void swelling, thermal and neutron embrittlement, etc. Evaluate

industry recommendations.One-time inspection

between years 30-40 on

most susceptible single unit (Surry or North Anna). Additional inspections based on results. (Complete)Table B4.0 33 15.Implement changes into

procedures to as sure consistent inspection of components for

aging ef fects during work activities.

Prior to Period of Extended

Operation (Complete)Table B4.0 33Table 18-1 (CONTINUED)

LICENSE RENEWAL COMMITMENTS Item Commitment Schedule aSourceRef.a.The Period of Extended operation is the period of 20 years beyond the expiration date of each unit's original operating license. For North Anna Unit 1, the Period of Extended Operation is from April 2, 2018 to April 1, 2038 and for North Anna Unit 2, from August 22, 2020 to August 21, 2040.b.Table B4.0 is the table of Licensee Followup Actions located in the License Renewal Application for North Anna (Reference 33).

Revision 52-09/29/2016 NAPS UFSAR 18-39 16.Incorporate groundwater monitoring into the civil engineering structural monitoring program. Consider groundwater chemistry in

engineering evaluations of deficiencies.

Prior to Period of Extended

Operation (Complete)

RAI 3.5-2 30 17.Incorporate management of

concrete aging into the civil structural monitoring program

and the infrequently accessed area in spection programs.

Prior to Period of Extended

Operation RAI 3.5-7 30 18.Incorporate management of

elastomers into the work control activities.

Prior to Period of Extended

Operation (Complete)

RAI 3.5.6-4, RAI B2.2.19-3 32 30 19.Develop and implement inspection program for

Non-EQ cables.

One-time between years

30-40. Additional

inspections every 10 years thereafter. (Complete)

RAI 3.6.2-1 30 20.Follow industry activities related to Alloy 82/182 weld material. Implem ent activities based on industry recommendations, as appropriate.

On-going activity (Complete)

RAI 4.7.3-1 29 21.Inspectors credited in the Work Control Process will be VT

qualified.

Prior to Period of Extended

Operation RAI B2.2.19-1 30Table 18-1 (CONTINUED)

LICENSE RENEWAL COMMITMENTS Item Commitment Schedule aSourceRef.a.The Period of Extended operation is the period of 20 years beyond the expiration date of each unit's original operating license. For North Anna Unit 1, the Period of Extended Operation is from April 2, 2018 to April 1, 2038 and for North Anna Unit 2, from August 22, 2020 to August 21, 2040.b.Table B4.0 is the table of Licensee Followup Actions located in the License Renewal Application for North Anna (Reference 33).

Revision 52-09/29/2016 NAPS UFSAR 18-40 22.Perform audit of work control inspections to ensure representation by all in-scope license renewal systems and to determine n eed for supplemental inspections.

Prior to Period of Extended Operation and every 10 years thereafter.

Supplemental inspections within 5 years of audit.

RAI B2.2.19-3 30 23.Measure the sludge buildup in

the SW reservoir at North Anna.One-time between years 35

and 40 RAI 3.5.8-2 28 , 32 24.Provide inspection details for pressurizer surge line inspections to the NRC for review and approval.

Prior to Period of Extended Operation (Complete)

RAI 4.3-7, RAI 4.3-6 27 25.Provide inspection details for SI and char ging line inspections to the NRC for

review and approval if analysis

is not successful in reducing the CUF below 1.0. The analysis described in

Reference 35 confirms the CUFs to be below 1.0, and no

inspections are required.

Prior to Period of Extended

Operation (Complete)

RAI 4.3-6, 27 , 34 26.Address NRC staff final

guidance regarding fuse

holders when issued.

When issued or prior to

Period of Extended

Operation, whichever is later. (Complete)

See Reference 25 27.Not applicable to North AnnaN/A N/A N/A 28.Revise procedures for groundwater testing to account for possible seasonal variations.

Prior to Period of Extended

Operation (Complete)

See Reference 26Table 18-1 (CONTINUED)

LICENSE RENEWAL COMMITMENTS Item Commitment Schedule aSourceRef.a.The Period of Extended operation is the period of 20 years beyond the expiration date of each unit's original operating license. For North Anna Unit 1, the Period of Extended Operation is from April 2, 2018 to April 1, 2038 and for North Anna Unit 2, from August 22, 2020 to August 21, 2040.b.Table B4.0 is the table of Licensee Followup Actions located in the License Renewal Application for North Anna (Reference 33).

Revision 52-09/29/2016 NAPS UFSAR 18-41 29.Inspect similar material/environment components, both within the

system and outside the system, if aging identified in a location

within a system cannot be explained by environmental/operational

conditions at that specific location.Prior to Period of Extended

Operation (Complete)

RAI B2.2.19-3 30 30.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.

Prior to Period of Extended Operation (Complete)

RAI B2.2.7-2 28 , 30Table 18-1 (CONTINUED)

LICENSE RENEWAL COMMITMENTS Item Commitment Schedule aSourceRef.a.The Period of Extended operation is the period of 20 years beyond the expiration date of each unit's original operating license. For North Anna Unit 1, the Period of Extended Operation is from April 2, 2018 to April 1, 2038 and for North Anna Unit 2, from August 22, 2020 to August 21, 2040.b.Table B4.0 is the table of Licensee Followup Actions located in the License Renewal Application for North Anna (Reference 33).

Revision 52-09/29/2016 NAPS UFSAR 18-42 Intentionally Blank