ML21063A560

Final Request for Additional Information Set 1 - North Anna SLRA Safety Review (EPID L-2020-SLR-0000) - Enclosure

ML21063A560
Person / Time
Site:	North Anna
Issue date:	03/04/2021
From:	NRC/NRR/DNRL/NLRP
To:
James L, NRR/DNRL/NLRP, 301-415-3306
Shared Package
ML21063A540	List: ML21063A552 ML21063A560
References
EPID L-2020-SLR-0000
Download: ML21063A560 (23)

Text

NORTH ANNA POWER STATION, UNITS 1 AND 2 (NAPS)

SUBSEQUENT LICENSE RENEWAL APPLICATION (SLRA)

REQUESTS FOR ADDITIONAL INFORMATION (RAIS)

SAFETY - SET 1

1. SLRA Section 3.5.2.2.2.6, Reduction of Strength and Mechanical Properties of Concrete Due to Irradiation Regulatory Basis Paragraph 54.21(a)(1) of 10 CFR requires license renewal applicants to perform an integrated plant assessment and their application to identify and list systems, structures, and components (SSCs) that are within the scope of license renewal and subject to an AMR item.

Paragraph 54.21(a)(3) 10 CFR requires for the identified SSCs that the effects of aging will be adequately managed such that their intended functions are maintained consistent with the CLB for the subsequent period of extended operation. To complete its review and enable the staff making a reasonable assurance finding on functionality of reviewed SSCs consistent with 10 CFR 54.21, the staff requires under 10 CFR 54.29(a) additional information for the subsequent period of extended operation be provided regarding the matters described below.

RAI 3.5.2.2.2.6-1

Background

SLRA Section 3.5.2.2.2.6, as amended by Supplement 1 dated February 4, 2021, discusses for NAPS Units 1 and 2 the effects of aging manifested as loss of fracture toughness due to neutron irradiation embrittlement on each reactor vessel (RV) support steel materials in the neutron shield tank (NST). The applicant's loss of fracture toughness evaluation is based on a methodology detailed in Project Topical Report (PTR): Reactor Vessel Support for Unit No 1 Surry Power Station, Life Extension Evaluation of the Reactor Vessel Support, including Appendix 3, Resistance to Brittle Fracture of the Neutron Shield Tank Materials, dated October 10, 1986 reviewed and evaluated in Surry SER (ADAMS Accession No. ML20052F523). Based on the PTR, Dominion authored the audited documents for SLR ETE-SLR-2019-2203 Review of Loads on Neutron Shield Tank for NAPS Units 1 & 2 Reactor Vessel Supports, Revision 0 and ETE-SLR-2020-2204, Assessment of Radiation Effects on Reactor Vessel Supports for NAPS Units 1 & 2, Revision 0. The staff reviewed Procedure ETE-SLR-2020-2204 and noted a discrepancy in the discussion regarding the structural integrity (i.e., embrittlement of welded steel plates) of the NST with that in SLRA Section 3.5.2.2.2.6.

Issue In the evaluation of the reactor vessel steel supports in SLRA Section 3.5.2.2.2.6 as amended by Supplement 1, Dominion evaluated the loss of fracture toughness of the steel plates of the NAPS Units 1 and 2 NSTs through fracture mechanics calculations as noted in the Background above. The staff however noted that, there was no discussion whether the fracture mechanics evaluations were applicable to the weldments and associated heat affected zones (HAZ) that join the individual steel plates of the NSTs. Since the weldments and HAZ of the NSTs have different material performance than those of the NST plates, the staff could not determine Enclosure

whether the fracture mechanics evaluations performed for the NST steel plates bound those of the weldments and HAZ, and if so how (by what margins).

Request

1) Clarify whether the fracture mechanics evaluations performed for the NST plates bound those of the weldments and HAZ

2) Explain how the fracture mechanics evaluations are bounding of the weldments and HAZ; Or, provide an evaluation (or other method) that sufficiently addresses the aging effect of loss of fracture toughness due to irradiation for weldments and HAZ of the NST steel plates RAI 3.5.2.2.2.6-2

Background

SLRA Section 3.5.2.2.2.6 as amended by Supplement 1, dated February 4, 2021, discusses the effects of aging manifested as loss of fracture toughness due to neutron irradiation embrittlement on each of NAPS Units 1 and 2 reactor vessel (RV) support steel materials in the NST. In its review of audited ETE-SLR-2020-2204, Assessment of Radiation Effects on Reactor Vessel Supports for NAPS Units 1 & 2, Revision 0, the staff noted that the applicants evaluation does not provide an allowance for potential loss of material due to internal corrosion.

The staff however noted in the audited NST fluid chemistry sampling history (Unit 1 and Unit 2 Sampling for 10 Years - Operating Experience Water Chemistry) that, although the level of Chromates in Unit 1 NST fluid are elevated to ensure corrosion protection, the tank has an elevated conductivity as well which could be indicative of potential corrosion.

Issue EPRI Report, Closed Cooling Water Guideline, Revision 2, identifies fluid conductivity as a diagnostic parameter for a corrosive environment. It recommends a conductivity value

( 2 S/cm) far less than those being reported for the NAPS NST Unit 1 fluid. For systems maintaining corrosion inhibitors (including high concentration of chromates - 2500 ppm at 150 0F), adequate pH levels and microbiological controls, the EPRI Report suggests that loss of material could occur in ferrous materials with values ranging from good (less than 0.3 mils per year year) to poor (greater than 0.5 mils per year). It is not clear whether the recorded high conductivity of the Unit 1 NST could be indicative of a potential loss of material in the tank that could affect its structural integrity, including its irradiated steel fracture mechanics evaluation.

However, it is also not clear if conductivity is a good diagnostic parameter for detection of such an aging effect, or simply an artifact of the NAPS Unit 1 NST fluid chemistry.

Request

1) Clarify why NAPS includes conductivity as a monitoring diagnostic parameter for the NST fluid.

2) Discuss the cause of increased conductivity in the Unit 1 NST.

3) Discuss whether the levels of high conductivity detected in the Unit 1 NAPS fluid are not of concern and whether conductivity should be used as a credible parameter for

detection of loss of material aging effect that could adversely affect the Unit 1 NST structural steel integrity, including the NST irradiated steel fracture mechanics evaluation.

RAI 3.5.2.2.2.6-3

Background

SLRA Section 3.5.2.2.2.6 as amended by Supplement 1, dated February 4, 2021, discusses the NAPS Units 1 and 2 RV structural steel supports that include their sliding foot assemblies and loading conditions used to calculate stresses for the fracture mechanics evaluation. It notes that the design load is based on dead weight combined with the square root of sum of the squares of design basis and LOCA loads. Section 18.3.5.3 of the UFSAR summarizes a Westinghouse detailed evaluation regarding large LOCAs and states that double-ended breaks of reactor coolant pipes are not credible, and as a result, large LOCA loads on primary system components will not occur.

The audited calculation CE-1634, The Effect of Reactor Pressure Vessel (RPV) Head Replacement on the RPV Support System Sliding Foot Assemblies and NST, NAPS Units 1 and 2, Revision 1, discusses the combined effects of seismic, pipe rupture, and deadweight loads on the RPV nozzle support pads and the NST for NAPS Unit 1 and 2. The calculations conclude that the RPV support system will maintain its structural integrity for all postulated loads with seismic loads re-evaluated based on response spectrum analysis (vs previous time history analyses). The document CE-1634-00A, addendum to CE-1634 titled Analysis of Loss of Coolant Accident (LOCA) Loads for impact on the RPV System, discusses dynamic analyses of NAPS Units 1 and 2 RPV supports based on Westinghouse provided displacements. After comparison of its results to CE-1634, this document also concludes that the maximum loads calculated from dynamic analysis of four LOCA cases (accumulator and pressurizer surge line breaks) are acceptable at the RPV nozzle supports and at the base of the NSTs.

Issue Despite the conservatism shown in Section 18.3.5.3 of the UFSAR for the reduction of pipe rupture loads and conclusions reached in CE-1634 and 1634-00A regarding the structural integrity of the RPV support system, the staff could not determine whether the effects of radiation on the RPV nozzle support pads/sliding foot assemblies were addressed for the subsequent period of extended operation. It is not clear whether results of the audited LTR-REA-20-3, Revision 0, North Anna Unit 1 and Unit 2 Neutron Shield Tank (NST) Neutron Fluence, have been considered in evaluating the structural adequacy of the RPV nozzle support pads/sliding foot assemblies for the subsequent period of extended operation.

Request For the RPV nozzle support pads/sliding foot assemblies:

1) Clarify whether the aging effects of streaming radiation have been considered in evaluating their structural adequacy.

2) Demonstrate, consistent with 10 CFR 54.21(a)(3), how the effects of aging [due to irradiation] will be adequately managed so that the[ir] intended function(s) will be maintained consistent with the CLB for the subsequent period of extended operation.

2. SLRA AMP B2.1.15, Fire Protection Regulatory Basis:

Paragraph 54.21(a)(3) of 10 CFR requires an applicant to demonstrate that the effects of aging for structures and components will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the period of extended operation. One of the findings that the staff must make to issue a renewed license (10 CFR 54.29(a)) is that actions have been identified and have been or will be taken with respect to managing the effects of aging during the period of extended operation on the functionality of structures and components that have been identified to require review under 10 CFR 54.21, such that there is reasonable assurance that the activities authorized by the renewed license will continue to be conducted in accordance with the CLB. In order to complete its review and enable making a finding under 10 CFR 54.29(a), the staff requests additional information regarding the matters described below.

RAI B2.1.15-1 (eRAI Letter #131, Question #199)

Background:

SLRA Section 2.1.5.1 states:

"A complex assembly is a predominantly active assembly where the performance of its components is closely linked to that of the intended function of the entire assembly, such that testing and monitoring of the assembly is sufficient to identify degradation of these components. to the extent that complex assemblies include piping or components that interface with external equipment, or components that cannot be adequately tested or monitored as part of the complex assembly, those components are identified and subject to aging management review."

SLRA Section 2.3.3-42, "Fire Protection," states that diesel-driven fire pump engine components within the skid boundaries are part of the active assembly and are not subject to AMR. SLRA Drawing 11715-SLRB-41B does not show the heat exchanger for diesel-driven fire pump engine coolant as being within the scope of license renewal (i.e., not highlighted and not within the scoping flag for the fire protection system). The associated note says that the heat exchanger is part of a skid-mounted, active assembly (engine) and therefore not subject to AMR.

The independent industry operating experience database includes an August 20, 2017, event at North Anna where the diesel-driven fire pump engine coolant heat exchanger developed a leak.

After the heat exchanger tube bundle was removed, several tubes were noted as visibly leaking.

The event was classified as a maintenance preventable functional failure, because it could not be confirmed how long the engine would run with the heat exchanger leaking. The functional failure evaluation noted that the "zero run-to-failure" criteria for this component was too restrictive, because the pump only serves as an emergency backup for non-fire accident mitigation, which is not a risk significant function.

The staff notes that, for initial license renewal, SLRA Table 3.3.9-1, "Fire Protection," included AMR items for "Diesel Fire Pump Radiator" to manage loss of material and heat transfer degradation using the Fire Protection Program. This scoping/screening approach is consistent with NUREG-2192, "Standard Review Plan for Review of Subsequent License Renewal,"

(SRP-SLR) Table 2.1-2, "Specific Staff Guidance on Scoping," for complex assemblies and

Table 2.1-6, "Typical Structures, Components, and Commodity Groups, and 10 CFR 54.21(a)(1)(i) Determinations for Integrated Plant Assessment," for all heat exchangers.

However, comparable AMR items are not included in SLRA Table 3.3.242, "Fire Protection," for subsequent license renewal. The staff also notes that the industry's consideration of "complex assemblies," as provided in NEI 95-10, "Industry Guideline for Implementing the Requirements of 10 CFR Part 54 - The License Renewal Rule," (subsequently endorsed by the NRC for both initial and subsequent license renewal) has not changed since initially being issued in 1996.

The staff further notes that SRP-SLR Section 2.1.2.1, "Scoping," indicates that justifications for any scoping exceptions should provide a reasonable basis for an exception.

Issue:

The absence of highlighting and the system flag location for the diesel-driven fire protection pump engine coolant heat exchanger on the associated drawing indicates that the heat exchanger is not credited by the current licensing bases for performing an intended function within the scope of license renewal. However, the discussion in the associated drawing note, regarding the component not being subject to an AMR, implies that the heat exchanger is within the scope of license renewal, but was screened-out. The associated statement in SLRA Section 2.3.3-42 only refers to skid mounted "components" and does not specifically address the heat exchanger. During break-out session discussions, Virginia Electric and Power Company (Dominion Energy or the applicant) participants stated that the heat exchanger was within the scope of license renewal and clarified that the lack of highlighting on the drawing did not mean that the heat exchanger was not within the scope of license renewal.

SRP-SLR Table 2.3-2, "Examples of Mechanical Components Screening and Basis for Disposition," notes that diesel engine jacket water heat exchangers supplied by a vendor on a diesel generator skid are passive, long-lived components having intended functions that are subject to an AMR even though the diesel generator is considered "active." During break-out session discussions, applicant engineers said that the size difference between a diesel generator engine and a diesel-driven fire pump engine justifies the different approach for AMR.

The staff notes that all heat exchangers have always been considered as passive, long-lived components that are subject to AMR, as reflected in SRP-SLR, Table 2.1-6.

SLRA Section 2.1.5.1 states that if components cannot be adequately tested or monitored as part of the complex assembly, then those components are identified and subject to AMR.

Based on North Anna operating experience, it is not clear that the heat exchanger for the diesel-driven fire pump engine can be adequately tested or monitored as part of the complex assembly and whether it should be identified and subject to aging management review.

Based on the NAPS initial license renewal application, the diesel-driven fire protection pump engine coolant heat exchanger was screened-in, consistent with the longstanding guidance for diesel engine jacket water heat exchangers. Although the screening of this component for the SLRA does not follow the current guidance in SRP-SLR, the staff notes that screening can be inconsistent with the guidance if justification is provided with a reasonable basis for the inconsistency.

Request:

1) Confirm that the fire protection diesel-driven pump engine coolant heat exchanger and associated components are within the scope of license renewal. If not, provide the bases to show that the diesel-driven fire pump can perform its current licensing basis

intended function without the engine coolant heat exchanger or associated piping and components.

2) Given that the existing testing and monitoring of the "active assembly" (i.e., skid-mounted fire protection diesel-driven pump engine components) were unable to identify degradation of the engine coolant heat exchanger prior to a functional failure:

a. discuss what changes were made to the testing and monitoring in order to demonstrate that the effects of aging will be adequately managed, comparable to that required by 10 CFR 54.21(a)(3).

b. because the functional failure analysis notes that the "zero run-to-failure" criteria was too restrictive, discuss whether the criteria for the assembly has been changed.

c. because the testing and monitoring activities of the assembly will not be part of an AMR, describe how these activities will be annotated to ensure that the applicable effects of aging for the diesel engine heat exchanger will continue to be managed during the subsequent period of extended operation.

3. SLRA AMP B2.1.21, Selective Leaching RAI B2.1.211 (eRAI Letter #155, Question #253)

(Selective Leaching - Basis for Extent of Inspections for Gray Cast Iron Exposed to Soil)

Regulatory Basis Title 10 of the Code of Federal Regulations (10 CFR) 54.21(a)(3) requires an applicant to demonstrate that the effects of aging for structures and components will be adequately managed so that the intended function(s) will be maintained consistent with the current licensing basis for the period of extended operation. One of the findings that the staff must make to issue a renewed license (10 CFR 54.29(a)) is that actions have been identified and have been or will be taken with respect to managing the effects of aging during the period of extended operation on the functionality of structures and components that have been identified to require review under 10 CFR 54.21, such that there is reasonable assurance that the activities authorized by the renewed license will continue to be conducted in accordance with the current licensing basis. In order to complete its review and enable making a finding under 10 CFR 54.29(a), the staff requires additional information in regard to the matters described below.

Background

As amended by letter dated February 4, 2021 (ADAMS Accession No. ML21035A303), SLRA Table 3.3.2-42, "Auxiliary Systems - Fire Protection - Aging Management Evaluation," states that loss of material due to selective leaching for gray cast iron piping and piping components exposed to soil will be managed by the Selective Leaching program.

SLRA Section B2.1.21, "Selective Leaching," states the following:

• "[t]he Selective Leaching program is a new program that, when implemented, will be consistent, with [GALL-SLR Report AMP] XI.M33, Selective Leaching."

• "[a] sample of 3% of the population or a maximum of ten components per population at each unit will be visually and mechanically (gray cast iron and ductile iron components) inspected."

• "[o]pportunistic and periodic inspections will be conducted for raw water, wastewater, soil, and groundwater environments."

• "[p]periodic destructive examinations of components for physical properties (i.e., degree of dealloying, through-wall thickness, and chemical composition) will be conducted for components exposed to raw water, wastewater, soil, and groundwater environments."

NUREG-2222, "Disposition of Public Comments on the Draft Subsequent License Renewal Guidance Documents NUREG-2191 and NUREG-2192," provides the following bases for reducing the extent of inspections for selective leaching during the subsequent period of extended operation (i.e., 3 percent with a maximum of 10 components per GALLSLR Report guidance) from comparable extent of inspections during the initial period of extended operation (i.e., 20 percent with a maximum of 25 components per GALL Report, Revision 2 guidance):

1) Opportunistic inspections will be conducted throughout the period of extended operation whenever components are opened, [or] buried or submerged surfaces are exposed, whereas opportunistic inspections were not recommended in the previous version of AMP XI.M33;

2) Destructive examinations provide a more effective means to detect and quantify loss of material due to selective leaching;

3) The slow growing nature of selective leaching generally coupled with the inspections conducted prior to the initial period of extended operation provides insights into the extent of loss of material due to selective leaching that can be used in the subsequent period of extended operation;

4) The staff's review of many license renewal applications (LRAs) has not revealed any instances where loss of intended function has occurred due to selective leaching;

5) The staff's review of industry operating experience (OE) has not detected any instances of loss of material due to selective leaching, which resulted in a loss of intended function for the component; and

6) Regional inspector input (provided based on IP 71003, "Post-Approval Site Inspection for License Renewal,") that selective leaching has been noted during visual and destructive inspections; however, no instances have been identified where there was the potential for loss of intended function.

The NRC issued Information Notice (IN) 2020-04, "Operating Experience Regarding Failure of Buried Fire Protection Main Yard Piping," to inform the industry of OE involving the loss of function of buried gray cast iron fire water main yard piping due to multiple factors, including graphitic corrosion (i.e., selective leaching), overpressuration, lowcycle fatigue, and surface loads. As noted in the IN, a contributing cause to the failures of buried gray cast iron piping at Surry Power Station (SPS) was the external reduction in wall thickness at several locations due to graphitic corrosion.

During its audit, the staff reviewed a summary of buried piping inspections performed for initial license renewal and noted that a single fire protection valve was destructively examined for selective leaching, which identified some isolated interior and exterior locations of graphitic corrosion. The staff also noted that although North Anna Power Station (NAPS) inspected a number fire protection piping segments as part of its underground piping and tank integrity program, the results did not specify whether visual inspections had been augmented with mechanical examination techniques, such as chipping or scraping. The staff notes that, as discussed in GALL-SLR Report AMP XI.M33, graphitized cast iron cannot be reliably identified through visual examination.

Issue The recommended extent of inspections in GALLSLR AMP XI.M33 are based on the six conditions noted by the staff in NUREG-2222. The staff's comparison to these six conditions to the Selective Leaching program at NAPS follows:

• Based on its review of SLRA Section B2.1.21, the staff notes that opportunistic inspections and destructive examinations for selective leaching will be performed, consistent with the first and second conditions in NUREG-2222.

• Although the staff previously accepted the reduced extent of inspections in GALLSLR AMP XI.M33 for a site that had not performed multiple selective leaching inspections prior to the first period of extended operation (Ref: Safety Evaluation Report Related to the Subsequent License Renewal of Peach Bottom Atomic Power Station, Units 2 and 3 (ADAMS Accession No. ML20044D902)), the staff subsequently became aware of operating experience at Peach Bottom after the issuance of the above safety evaluation report. The subsequent operating experience was a circumferential crack in buried gray cast iron piping attributed to external reduction in wall thickness (approximately 60 to 65 percent wall loss) due to graphitic corrosion. This information causes the staff to reconsider its previous position on the third condition, absent additional information.

• The fourth, fifth, and sixth conditions in NUREG2222 focus on the staff's review of industry OE not identifying any instances of loss of material due to selective leaching which had resulted in a loss of intended function for the component. Based on recent industry OE at SPS (as documented in IN202004), the last three conditions in NUREG2222 are no longer applicable for gray cast iron piping exposed to soil. Since these conditions are no longer applicable (i.e., there is now industry OE involving loss of material due to selective leaching which resulted in a loss of intended function for gray cast iron piping exposed to soil), the staff requires additional information to determine if the reduced extent of inspections in GALLSLR AMP XI.M33 are appropriate for this material and environment combination.

Request Provide a technical justification for using the extent of inspections in GALLSLR AMP XI.M33 for gray cast iron piping and piping components exposed to soil.

RAI B2.1.21-2 (eRAI Letter #157, Question #259)

Regulatory Basis Title 10 of Code of Federal Regulations (10 CFR) 54.21(a)(3) requires an applicant to demonstrate that the effects of aging for structures and components will be adequately managed so that the intended function(s) will be maintained consistent with the current licensing basis for the period of extended operation. One of the findings that the staff must make to issue a renewed license (10 CFR 54.29(a)) is that actions have been identified and have been or will be taken with respect to managing the effects of aging during the period of extended operation on the functionality of structures and components that have been identified to require review under 10 CFR 54.21, such that there is reasonable assurance that the activities authorized by the renewed license will continue to be conducted in accordance with the current licensing basis. In order to complete its review and enable formulation of a finding under 10 CFR 54.29(a), the staff requires additional information regarding the matters described below.

Background

North Anna Power Station (NAPS) Subsequent License Renewal Application (SLRA)

Section B2.1.21, "Selective Leaching" states that it is a new program that will be consistent with the corresponding program in NUREG-2191, Generic Aging Lessons Learned for Subsequent License Renewal (GALL-SLR) Report aging management program (AMP) XI.M33, "Selective Leaching." The SLRA also states that the program includes eight visual and mechanical inspections of components as prescribed in AMP XI.M33 for two-unit sites with sufficiently similar operating conditions and history.

In the program element comparison between the NAPS program and the GALL-SLR Report AMP XI.M33, ETE-SLR-2020-2324, Rev. 0, Section 3.4.2 (for the detection of aging effects) states that inspections are conducted on each material and environment combination as provided in Attachment 2, "One-Time and Periodic Inspection Sample Population." Note 5 of states:

The buried selective leaching fire protection population is large bore gray cast iron piping and valves. One 8-foot piping segment at each unit can be excavated for the visual inspection (each one-foot segment is one sample). Excavating one 10-foot piping segment per unit will satisfy the visual inspections (8 samples) and the mandatory destructive examination (2 samples).

GALL-SLR Report AMP XI.M33, Detection of Aging Effects states that inspections are conducted of a representative sample of each population and that, where possible, focus on the bounding or lead components most susceptible to aging.

Issue:

Crediting eight 1-foot samples from a single location would appear to be eight samples of the same component instead of samples from eight different components. A similar issue applies to the two destructive samples from the same 10-foot segment. Unless the one 10-foot piping segment can be shown to be the most susceptible and bounding piping section, this sampling approach requires justification.

Request:

Provide the criteria (and justification of the adequacy of the approach) that will be used to select the single 10-foot piping section in order to show that eight visual and mechanical inspections and two destructive examinations of a single location will provide a representative sample of the entire population.

4. SLRA AMP B2.1.27, Buried and Underground Piping and Tanks Regulatory Basis:

Section 54.21(a)(3) of 10 CFR requires an applicant to demonstrate that the effects of aging for structures and components will be adequately managed so that the intended function(s) will be maintained consistent with the current licensing basis for the period of extended operation. One of the findings that the staff must make to issue a renewed license (10 CFR 54.29(a)) is that actions have been identified and have been or will be taken with respect to managing the effects of aging during the period of extended operation on the functionality of structures and components that have been identified to require review under 10 CFR 54.21, such that there is reasonable assurance that the activities authorized by the renewed license will continue to be conducted in accordance with the CLB. In order to complete its review and enable making a finding under 10 CFR 54.29(a), the staff requires additional information in regard to the matters described below.

RAI B2.1.27-1 (eRAI Letter #102, Question #147)

Background:

As amended by letter dated February 4, 2021 (ADAMS Accession No. ML21035A303), SLRA Table 3.3.2-42, "Auxiliary Systems - Fire Protection - Aging Management Evaluation," states that cracking for internallylined gray cast iron piping and piping components exposed to soil will be managed by the Buried and Underground Piping and Tanks program. The AMR item cites generic Note H, for which Dominion has identified cracking as an aging effect that is not in the GALL-SLR Report for this component, material, and environment combination. In addition, the AMR item cites plantspecific note 11, which states "[c]racking of buried gray cast iron piping due to cyclic loading is managed by the Buried and Underground Piping and Tanks (B2.1.27) program. CLB [current licensing basis] fatigue analysis does not exist."

The SLRA includes several statements related to failures of buried gray cast iron piping in the fire protection system:

• SLRA Section B2.1.16, "Fire Water System," states "[i]n May 2013, sections of cementitious lined cast iron piping were replaced with a higher pressure rated cementitious lined ductile iron piping. Additional isolation valves were also installed to improve system sectional isolation capability. These modifications were implemented due to six fire protection pipe failures that occurred from 1984 to 2003 because of either manufacturing flaws or a flaw that was initiated during the installation process. There were no reported instances due to age related degradation."

• SLRA Section B2.1.21, "Selective Leaching," states "[i]n October 2001 a rupture of fire protection main loop piping occurred. A metallurgical analysis determined that the failure

most likely occurred as a result of a low cycle fatigue process that originated at a preexisting manufacturing flaw in the pipe. The ruptured piping was replaced."

• SLRA Section B2.1.27, "Buried and Underground Piping and Tanks," states "[i]n May 2013, following replacement of cast iron with (and installation of new) ductile iron fire main piping, the scope of cast iron fire protection piping replacement with ductile iron was reduced to the portion identified as high priority due to the postulated pipe rupture in this area potentially challenging adjacent safety-related piping."

• SLRA Section 3.3.2.2.7, "Loss of Material Due to Recurring Internal Corrosion," states

"[b]uried fire protection system piping is made of cast iron or ductile iron with a cementitious lining. In May 2013, a design change was completed to replace sections of cementitious lined cast iron piping with a higher pressure rated cementitious lined ductile iron due to internal pipe failures that were attributed to preexisting conditions in the cast iron pipe and not due to the failure of the lining."

The staff's acceptance letter for the NAPS SLRA (ADAMS Accession No. ML20258A284) states the following:

• "[t]he application makes several references to buried gray cast iron piping in the "Fire Protection System." However, there are no aging management review items in Table 3.3.2-42, "Fire Protection," of the application for this component, material, and environment combination. The application states that sections of buried gray cast iron piping were replaced with ductile iron in 2013, but there is no mention of a full-scale replacement. Additionally, the Selective Leaching AMP discusses a failure due to cyclic fatigue, which is an aging effect not referenced in the GALL-SLR Report, for this component, material, and environment combination. The staff notes that the issue of cyclic fatigue of buried gray cast iron fire protection system piping will be subject to the NRC staff's detailed review and that it may require additional review time and requests for additional information (RAIs)."

During its audit, the staff reviewed additional documents discussing buried cast iron fire main pipe ruptures that noted preexisting flaws had grown as a result of low cycle fatigue from periodic system pump pressure testing. [

Reference:

Design Change No. 04018, "Underground Fire Protection Piping Replacement/ North Anna/ Units 1&2," dated May18, 2006]. The staff also reviewed the failure analysis associated with the 2001 rupture and noted the conclusion that "from a condition assessment standpoint, any pipe still in service that may contain an

[inside diameter] defect or flaw that is allowed to propagate to the size of four inches or greater will be susceptible to brittle fracture assuming it experiences similar loading conditions."

[

Reference:

NESML-Q-473, "Material Analysis Report," dated October 15, 2001.]

GALLSLR Table IX.F, "Use of Terms for Aging Mechanisms," lists cyclic loading as a standardized aging mechanism used in AMR line item tables in the GALL-SLR Report. In addition, the definition for cyclic loading states "[f]atigue cracking is a typical result of cyclic loadings on metal components."

Issue:

During its review, the staff notes that the February 4, 2021, supplement does not include changes to SLRA Section B2.1.27 with respect to how the Buried and Underground Piping and Tanks program will manage cracking due to cyclic fatigue for internallylined gray cast iron

piping and piping components exposed to soil. The staff also notes that GALLSLR Report AMP XI.M41 does not generically address management of cracking due to cyclic fatigue for buried components.

Request:

Provide additional information describing how the Buried and Underground Piping and Tanks program will manage cracking due to cyclic fatigue for internallylined gray cast iron piping and piping components exposed to soil.

RAI B2.1.272 (eRAI Letter #153, Question #249)

Regulatory Basis Paragraph 54.21(a)(3) of 10 CFR requires an applicant to demonstrate that the effects of aging for structures and components will be adequately managed so that the intended function(s) will be maintained consistent with the current licensing basis for the period of extended operation.

One of the findings that the staff must make to issue a renewed license (10 CFR 54.29(a)) is that actions have been identified and have been or will be taken with respect to managing the effects of aging during the period of extended operation on the functionality of structures and components that have been identified to require review under 10 CFR 54.21, such that there is reasonable assurance that the activities authorized by the renewed license will continue to be conducted in accordance with the current licensing basis. In order to complete its review and enable making a finding under 10 CFR 54.29(a), the staff requires additional information in regard to the matters described below.

Background

As amended by letter dated February 4, 2021, SLRA Section B2.1.27, "Buried and Underground Piping and Tanks," states the following:

• "[t]he Buried and Underground Piping and Tanks program is an existing program that, following enhancement, will be consistent, with NUREG-2191,Section XI.M41, Buried and Underground Piping and Tanks."

• "[t]he buried carbon steel piping of the service water system and the flood protection dike drain is protected by an active CP [cathodic protection] system."

• "[t]he buried carbon steel piping of the fuel oil system for the emergency electrical power system will be refurbished and reconnected to the service water CP system described above."

• [t]he buried carbon steel fill line piping for the security diesel fuel oil tank will be replaced with corrosion resistant material that does not require inspection (e.g., titanium alloy, super austenitic, or nickel alloy materials)."

GALL-SLR Report AMP XI.M41, "Buried and Underground Piping and Tanks," Table XI.M411, "Preventive Actions for Buried and Underground Piping and Tanks," recommends that cathodic protection is provided for buried steel piping and tanks. In addition, the "preventive actions" program element of GALL-SLR Report AMP XI.M41 states the following:

Failure to provide cathodic protection in accordance with Table XI.M41-1 may be acceptable if justified in the SLRA. The justification addresses soil sample locations, soil sample results, the methodology and results of how the overall soil corrosivity was determined, pipe to soil potential measurements and other relevant parameters.

If cathodic protection is not provided for any reason, the applicant reviews the most recent 10 years of plantspecific operating experience (OE) to determine if degraded conditions that would not have met the acceptance criteria of this AMP have occurred.

This search includes components that are not inscope for license renewal if, when compared to inscope piping, they are similar materials and coating systems and are buried in a similar soil environment. The results of this expanded plantspecific OE search are included in the SLRA.

SLRA Table 3.3.240, "Auxiliary Systems - Emergency Diesel Generator System - Aging Management Evaluation," states carbon steel tanks exposed to soil will be managed for loss of material using the Buried and Underground Piping and Tanks program.

Issue:

A basis was not provided for why cathodic protection is not necessary for carbon steel tanks exposed to soil in the emergency diesel generator system.

Request:

State the basis for why carbon steel tanks exposed to soil in the emergency diesel generator system are not provided with cathodic protection.

RAI B2.1.273 (eRAI Letter #153, Question #250)

Regulatory Basis Paragraph 54.21(a)(3) of 10 CFR requires an applicant to demonstrate that the effects of aging for structures and components will be adequately managed so that the intended function(s) will be maintained consistent with the current licensing basis for the period of extended operation.

One of the findings that the staff must make to issue a renewed license (10 CFR 54.29(a)) is that actions have been identified and have been or will be taken with respect to managing the effects of aging during the period of extended operation on the functionality of structures and components that have been identified to require review under 10 CFR 54.21, such that there is reasonable assurance that the activities authorized by the renewed license will continue to be conducted in accordance with the current licensing basis. In order to complete its review and enable making a finding under 10 CFR 54.29(a), the staff requires additional information in regard to the matters described below.

Background

GALL-SLR Report Table XI.M411 recommends that the following are externally coated in accordance with the "preventive actions" program element of GALL-SLR Report AMP XI.M41:

(a) buried steel and stainless steel components; and (b) underground steel and copper alloy components.

SLRA Section B2.1.27 states the following:

• "[d]epending on the material, preventive and mitigative techniques include external coatings"

• "[t]he required inspections of in-scope stainless steel piping were conducted [referring to Buried Piping and Valve Inspection program inspections performed prior to the initial period of extended operation]. In cases where stainless steel piping was found without coating or with significantly disbonded coating, no evidence of pitting or corrosion existed."

During the audit, the staff noted the following: (a) buried stainless steel piping may be coated, wrapped, or tape-wrapped; (b) stainless steel piping is not required to be coated based on chloride index value of zero for each of the 24 soil sample locations throughout North Anna Power Station; (c) buried steel piping may be coated with coal tar epoxy, coal tar enamel, coal tar epoxy encased in concrete; or tape wrap; (d) acceptable applied coatings for underground steel and copper alloy piping are coal tar enamel, coal tar epoxy, unidentified material, and none; and (e) the investigation into the cause of a leak due to external corrosion on a buried carbon steel service water line identified that the piping was not coated and wrapped in accordance with the installation specification.

UFSAR Section 3.11.3, "Corrosion Prevention for Underground Piping," states the following:

The protective steps and measures taken are in accordance with National Association of Corrosion Engineers (NACE)1 Recommended Practice RP-01-69. All underground steel pipelines and tanks are coated and wrapped in accordance with Section 5, Coatings, of the above standard. The standard does not address itself to stainless steel piping.

Analysis indicates that no protective coating is required. However, to provide additional protection for the buried stainless steel Fuel Oil piping an approved coating will be applied.

Issue The staff seeks confirmation on whether the following are coated in accordance with the "preventive actions" program element of GALL-SLR Report AMP XI.M41: (a) buried steel and stainless steel piping and piping components; and (b) underground steel and copper alloy piping and piping components. In addition, the staff notes the following: (a) plantspecific operating experience indicates that portions of inscope buried steel and stainless steel are not externally coated; (b) GALL-SLR Report AMP XI.M41 does not exclude buried stainless steel from being externally coated based on the nonpresence of chlorides; and (c) UFSAR Section 3.11.3 indicates that only buried stainless steel fuel oil piping is externally coated.

Request Provide clarification regarding if the following are coated in accordance with the "preventive actions" program element of GALL-SLR Report Table XI.M411: (a) buried steel and stainless 1 NACE RP-01-69, "Control of External Corrosion on Underground or Submerged Metallic Piping Systems." Houston, Texas: NACE International. 1983.

steel piping and piping components; and (b) underground steel and copper alloy piping and piping components. If all or portions of inscope piping and piping components are not externally coated in accordance with the "preventive actions" program element of GALL SLR Report AMP XI.M41, provide justification for why external coatings are not provided.

RAI B2.1.274 (eRAI Letter #153, Question #251)

Regulatory Basis Paragraph 54.21(a)(3) of 10 CFR requires an applicant to demonstrate that the effects of aging for structures and components will be adequately managed so that the intended function(s) will be maintained consistent with the current licensing basis for the period of extended operation.

One of the findings that the staff must make to issue a renewed license (10 CFR 54.29(a)) is that actions have been identified and have been or will be taken with respect to managing the effects of aging during the period of extended operation on the functionality of structures and components that have been identified to require review under 10 CFR 54.21, such that there is reasonable assurance that the activities authorized by the renewed license will continue to be conducted in accordance with the current licensing basis. In order to complete its review and enable making a finding under 10 CFR 54.29(a), the staff requires additional information in regard to the matters described below.

Background

SLRA Section A1.16, "Fire Water System," states "[t]his program manages cracking, flow blockage, and, loss of material by conducting periodic visual inspections, flow testing, and flushes performed in accordance with the NFPA [National Fire Protection Association] 25, 2011 Edition."

GALL-SLR AMP XI.M41 states for fire mains installed in accordance with NFPA 24, "Standard for the Installation of Private Fire Service Mains and Their Appurtenances,"2 preventive actions beyond those in NFPA 24 need not be provided if the system undergoes a periodic flow test in accordance with NFPA 253. The staff notes that NFPA 24 provides provisions for backfill quality in Section 10.9, "Backfilling."

During the audit, the staff noted plantspecific operating experience from 2012 where (a) unexpected backfill material was found against the surfaces of fire protection piping; (b) the backfill material contained gravel above the size of VDOT [Virginia Department of Transportation] Grade B granular fill material specified for the fire protection replacement project; and (c) the original fire protection installation specification does not identify a maximum backfill material size.

22 NFPA 24, "Standard for the Installation of Private Fire Service Mains and Their Appurtenances."

Quincy, Massachusetts: National Fire Protection Association. 2010.

333 NFPA 25, "Inspection, Testing, and Maintenance of Water-Based Fire Protection Systems, 2011 Edition." Quincy, Massachusetts: National Fire Protection Association. 2011.

Issue Based on its review of plantspecific operating experience during the audit, the staff was not able to confirm that the backfill quality for buried fire protection piping meets the intent of NFPA 24, Section 10.9.

Request State the basis for how backfill quality for buried fire protection piping meets the intent of NFPA 24, Section 10.9.

5. SLRA AMP B2.1.28, Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks RAI B2.1.281 (eRAI Letter #154, Question #252)

Regulatory Basis Paragraph 54.21(a)(3) of 10 CFR requires an applicant to demonstrate that the effects of aging for structures and components will be adequately managed so that the intended function(s) will be maintained consistent with the current licensing basis for the period of extended operation.

One of the findings that the staff must make to issue a renewed license (10 CFR 54.29(a)) is that actions have been identified and have been or will be taken with respect to managing the effects of aging during the period of extended operation on the functionality of structures and components that have been identified to require review under 10 CFR 54.21, such that there is reasonable assurance that the activities authorized by the renewed license will continue to be conducted in accordance with the current licensing basis. In order to complete its review and enable making a finding under 10 CFR 54.29(a), the staff requires additional information in regard to the matters described below.

Background

As amended by letter dated February 4, 2021, SLRA Section B2.1.28 states the following:

• "[t]he Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks program is an existing program that, following enhancement, will be consistent, with exception [not related to this RAI], to NUREG-2191,Section XI.M42, Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks as modified by SLR-ISG-Mechanical-2020-XX, Updated Aging Management Criteria for Mechanical Portions of the Subsequent License Renewal Guidance."

• "[f]rom 2014 to 2019 recurring internal corrosion (RIC) due to loss of coating integrity has occurred in the coated service water (SW) system piping and component cooling heat exchanger channel head."

• "[p]lant operating experience [OE] has demonstrated that component cooling heat exchanger channel heads inspections performed on a three-year frequency which allows early detection of degradation of coatings and the underlying metal before there is a loss of intended function."

GALLSLR Report Table XI.M42-1, "Inspection Intervals for Internal Coatings/Linings for Tanks, Piping, Piping Components, and Heat Exchangers," recommends that internal coatings/linings for piping, piping components, heat exchangers, and tanks are inspected every 4 or 6 years based on the inspection category.

Issue It appears that based on the plantspecific OE, the component cooling heat exchanger channel heads are inspected more frequently than the guidance provided in GALLSLR Report Table XI.M42-1. Given that the Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks program will be consistent with GALLSLR Report AMP XI.M42, the frequency of inspections of the component cooling heat exchanger channel heads could exceed the triennial inspection interval because the frequency of inspections is not reflected in the current licensing basis for the SPEO.

Request State the basis for why the triennial inspections of the component cooling heat exchanger channel heads is not reflected in the current licensing basis for the SPEO. Alternatively, revise the SLRA as appropriate to reflect a triennial inspection frequency for the component cooling heat exchanger channel heads.

6. SLRA AMP B2.1.34, Structures Monitoring Program Regulatory Basis:

Paragraph 54.21(a)(3) of 10 CFR requires an applicant to demonstrate that the effects of aging for structures and components will be adequately managed so that the intended function(s) will be maintained consistent with the current licensing basis for the period of extended operation.

RAI B2.1.34-1

Background

SLRA Section B2.1.34 states that the Structures Monitoring Program will be consistent with the ten [program] elements of GALL-SLR Report AMP XI.S6, "Structures Monitoring". As described in the SRP-SLR, and to ensure compliance with the 10 CFR 54.21(a)(3) requirements, for those programs that the applicant claims are consistent with the GALL-SLR Report, the NRC staff will verify that the applicants programs are consistent with those described in the GALL-SLR Report and/or with plant conditions and operating experience during the performance of an AMP audit and review.

In SLRA Section B2.1.34, Dominion included enhancement No. 3 to the Structures Monitoring Program to demonstrate consistency with the parameters monitored or inspected program element of the GALL-SLR Report AMP XI.S6. This enhancement states, in part, that procedures will be revised to specify that aluminum and stainless steel (SS) structural components such as louvers, cable trays, conduits, and structural supports will be monitored for cracking due to Stress Corrosion Cracking.

Issue The enhancement provided in SLRA Section B2.1.34 suggests that only the aging effects of cracking will be monitored for the aluminum and SS structural components.

SRP-SLR Section 3.5.2.2.2.4 recommends enhancing the applicable AMP (i.e. Structures Monitoring Program) to ensure that aging effects of loss of material and cracking are adequately managed for SS and aluminum components during the period of extended operations.

Request Clarify if the aging effect of loss of material will be monitored for aluminum and stainless steel structural components within the scope of the Structures Monitoring Program, or provide a technical justification for not monitoring this aging effect for these components. Revise the SLRA and enhancement No. 3 accordingly.

RAI 3.5.2.3-1

Background

SLRA Table 3.5.2 26 states that hardening or loss of strength, loss of material, and cracking or blistering of carbon fiber reinforced polymer wrap exposed to air will be managed by the Structures Monitoring Program. The AMR item cites generic note H, since these aging effects are not generally addressed in the GALL-SLR Report for this component, material and environment combination by the Structures Monitoring Program.

As described in the SRP-SLR, AMR results not consistent with or not addressed in the GALL-SLR Report need to follow the acceptance criteria described in Appendix A.1 of the SRP-SLR.

Specifically, the credited program should, in part, identify the specific structures and/or components within scope of the program, identify the aging effects that the program manages, and describe the acceptance criteria that will be used to ensure that the intended function(s) are maintained consistent with the CLB during the subsequent period of extended operation.

Issue During the audit, the staff reviewed procedure ER-NA-INS-104, Revision 10, Monitoring of Structures North Anna Power Station, and noted that the scope of the existing program does not include the carbon fiber reinforced polymer wrap material/component, its associated aging effects (i.e. aging effects of hardening, loss of strength, loss of material, cracking or blistering),

and associated acceptance criteria. The staff also noted that SLRA Section B2.1.34 does not include an enhancement to the Structures Monitoring Program to ensure that this component, aging effects, and acceptance criteria are added to the scope of the program to ensure compliance with the 10 CFR 54.21(a)(3) requirements.

Request Provide the necessary information and/or enhancement to demonstrate that carbon fiber reinforced polymer wrap will be in the scope of the Structures Monitoring Program (or other appropriate AMP) and that the effects of aging for this component will be adequately managed for the period of extended operation.

7. SLRA TLAA 4.3, Metal Fatigue Regulatory Basis:

Pursuant to 10 CFR 54.21(c), the SLRA shall include an evaluation of time-limited aging analyses (TLAAs). The applicant shall demonstrate that (i) the analyses remain valid for the period of extended operation; (ii) the analyses have been projected to the end of the period of extended operation; or (iii) the effects of aging on the intended function(s) will be adequately managed for the period of extended operation.

RAI 4.3-1 (eRAI Letter #149, Question #245)

Background:

As described in SLRA Section 4.3.2.6, the applicant proposed to disposition the TLAA for the Pressurizer (including Nozzle Weld Overlays) in accordance with 10 CFR 54.21(c)(1)(iii), by demonstrating that the effects of fatigue on the intended functions of these components will be adequately managed for the subsequent period of extended operation. Specifically, the applicant stated that the effects of fatigue on the intended function(s) of the pressurizer surge line will be adequately managed by the Fatigue Monitoring program (SLRA Section B3.1) for the subsequent period of extended operation. The application also states that the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD program (SLRA Section B2.1.1) will manage the pressurizer surge line thermal stratification through inspection every ten years based upon the ASME Code,Section XI, Appendix L methodology approved by the NRC.

As described in SLRA Section 4.3.2.7, the applicant proposed to disposition the TLAA for the Class 1, United States of America Standards (USAS) (American National Standards Institute (ANSI)) B31.7 Piping in accordance with 10 CFR 54.21(c)(1)(i), by demonstrating that the analyses for these components remain valid for the subsequent period of extended operation.

As described in SLRA Section 4.3.6, the applicant proposed to disposition the TLAA for the High Energy Line Break Analyses in accordance with 10 CFR 54.21(c)(1)(i), by demonstrating that the analyses for these components remain valid for the subsequent period of extended operation.

With respect to the TLAAs described above in SLRA Sections 4.3.2.6 and 4.3.2.7, SLRA Section A3.3.2 states that the effects of fatigue on the intended function(s) of ASME Code,Section III components will be adequately managed by the Fatigue Monitoring program (Section A2.1) for the subsequent period of extended operation in accordance with 10 CFR 54.21(c)(1)(iii).

With respect to the TLAA described above in SLRA Section 4.3.6, SLRA Section A3.3.6 states that the effects of fatigue on the intended function(s) of ASME Code,Section III components will be adequately managed by the Fatigue Monitoring program (Section A2.1) for the subsequent period of extended operation in accordance with 10 CFR 54.21(c)(1)(iii).

Issue:

The applicant's proposed disposition of the TLAAs described in SLRA Sections 4.3.2.6, 4.3.2.7 and 4.3.6 are inconsistent with the Updated Final Safety Analysis Report (UFSAR) Supplement for these TLAAs in Appendix A.

Specifically, the staff noted the following inconsistencies:

• SLRA Section A3.3.2 does not indicate that the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD program (B2.1.1) will manage the pressurizer surge line thermal stratification through inspection every ten years based upon the ASME Code,Section XI, Appendix L methodology approved by the NRC.

• SLRA Section A3.3.2 indicates the disposition for the Class 1, USAS (ANSI) B31.7 Piping TLAA is in accordance with 10 CFR 54.21(c)(1)(iii), whereas SLRA Section 4.3.2.7 indicates that this TLAA is dispositioned in accordance with 10 CFR 54.21(c)(1)(i).

• SLRA Section A3.3.6 indicates the disposition for the High-Energy Line Break TLAA is in accordance with 10 CFR 54.21(c)(1)(iii), whereas SLRA Section 4.3.6 indicates that this TLAA is dispositioned in accordance with 10 CFR 54.21(c)(1)(i).

Request:

Clarify the discrepancy identified between SLRA Section 4.3 and Appendix A of the SLRA.

Provide a revision to the SLRA, if necessary.

RAI 4.3-2 (eRAI Letter #149, Question #246)

Regulatory Basis Pursuant to 10 CFR 54.21(c), the SLRA shall include an evaluation of TLAAs. The applicant shall demonstrate that (i) the analyses remain valid for the period of extended operation; (ii) the analyses have been projected to the end of the period of extended operation; or (iii) the effects of aging on the intended function(s) will be adequately managed for the period of extended operation.

Background

As described in SLRA Section 4.3.4, the applicant proposed to disposition the TLAA for Environmentally Assisted Fatigue in accordance with 10 CFR 54.21(c)(1)(iii), by demonstrating that the effects of fatigue on the intended functions of these components will be adequately managed for the subsequent period of extended operation.

SLRA Section 4.3.4 states that calculations were prepared to document the evaluations of environmentally-assisted fatigue (EAF) for ASME Code,Section III pressure boundary components and USAS (ANSI) B31.7, Class I piping that contact the reactor coolant, and determine fatigue-sensitive locations for comparison and ranking.

Issue During its audit, the staff noted that SIA Report 1701098.403P, Revision 0, "Determination of Final Set of Environmentally-Assisted Fatigue (EAF) Sentinel Locations for North Anna Power Station (NAPS) Units 1 and 2," determined the pressurizer surge nozzle weld overlay (nickel-based alloy) is bounded by the (a) replacement reactor vessel closure head J-groove weld (nickel-based alloy) and (b) 14" hot leg surge nozzle (stainless steel). The basis provided in SIA Report 1701098.403P (i.e., environmentally-adjusted cumulative usage factor (CUFen) of the bounding locations are greater than pressurizer surge nozzle weld overlay (nickel-based alloy)

is not sufficient. Specifically, the applicant did not adequately justify that (1) a component of the same material from a different transient section is bounding, and (2) a component of different material from the same transient section is bounding. The staff noted that aspects such as, but not limited to, the amount of rigor in calculating CUF, the use of the same fatigue curves (if applicable), and the assessment of differences in material properties for nickel based alloy and stainless steel and in severity of transients in these transient sections, can impact CUFen values; thus, only a comparison of CUFen values for these components is not sufficient.

In addition, SLRA Section 4.3.4 states the following: "[f]or two pressurizer FSWOL nozzle locations with Uen values greater than unity, Surge Nozzle (Ni-Cr-Fe), and Spray Nozzle (stainless steel pipe to safe weld) these locations will be managed through the Fatigue Monitoring program (SLRA Section B3.1) during the subsequent period of extended operation.

While not required for EAF since these full structural weld overlays are managed by the Fatigue Monitoring program (SLRA Section B3.1), they are inspected in accordance with ASME Code Case N-770-2."

However, the supporting technical basis (SIA Report 1701098.403P, Revision 0) is inconsistent with the SLRA and indicates that only the nickel-based alloy portion of the pressurizer spray nozzle weld overlay weld will be inspected per ASME Code Case N-770-2.

Thus, the following requires clarification:

• The supporting technical basis that the pressurizer surge nozzle weld overlay (nickel-based alloy) is bounded by the (a) replacement reactor vessel closure head J-groove weld (nickel-based alloy) and (b) 14" hot leg surge nozzle (stainless steel) for environmentally assisted fatigue during the subsequent period of extended operation.

• Whether the pressurizer surge nozzle weld overlay (nickel-based alloy) is inspected in accordance with ASME Code Case N-770-2.

Request

1. With respect to environmentally assisted fatigue during the subsequent period of extended operation, provide the supporting technical basis that the pressurizer surge nozzle weld overlay (nickel-based alloy) is bounded by the replacement reactor vessel closure head J-groove weld (nickel-based alloy) and 14" hot leg surge nozzle (stainless steel).

2. Clarify whether the pressurizer surge nozzle weld overlay (nickel-based alloy) will be inspected in accordance with ASME Code Case N-770-2 and is credited for aging management during the subsequent period of extended operation.

8. SLRA TLAA 4.7.3, Leak-Before-Break Regulatory Basis:

In accordance with 10 CFR 54.21(c)(1), the applicant is required to provide a list of TLAAs as defined in 10 CFR 54.3. The applicant is also required to demonstrate that: (i) the analyses remain valid for the period of extended operation; (ii) the analyses have been projected to the end of the subsequent period of extended operation; or (iii) the effects of aging on the intended function(s) will be adequately managed for the subsequent period of extended operation.

Background:

Section 4.7.3 of NAPS SLRA addresses the leak-before-break (LBB) time-limited aging analysis (TLAA) for NAPS Units 1 and 2. As part of the SLRA, the applicant (Dominion Energy) also submitted WCAP-11163, Revision 2 that describes the technical basis of the LBB TLAA.

WCAP-11163, Revision 2 indicates that NAPS has unmitigated Alloy 82/182 welds at Unit 1 steam generator outlet nozzles, which is susceptible to primary water stress corrosion cracking (PWSCC). Specifically, Section 7.3 of the WCAP report states that a conservative factor of 1.69 to account for PWSCC is applied to the leakage flaw size calculation. During the audit on January 4. 2021, the applicant explained that the conservative factor accounts for the effect of PWSCC crack morphology on leakage rates in the LBB analysis and that the approach is consistent with that used in WCAP-17187 and WCAP-17262, Revision 1, which describe previous LBB analyses for other plants.

RAI 4.7.3-1 (eRAI Letter #146, Question #238)

Request:

The staff noted that the conservative factor for Alloy 82/182 welds previously used in WCAP-17262, Revision 1, Table 6 1 and the related analysis suggest that a conservative factor greater than 1.69 is applied to account for the effect of PWSCC crack morphology. In addition, WCAP-11163, Revision 2 for NAPS does not clearly address an analysis of crack growth from the leakage crack to the critical crack in order to confirm that the crack growth will take a sufficient time to detect leakage and shut down the reactor safely. Based on the discussion above, provide the following information.

1. If the LBB TLAA uses a conservative factor for Alloy 82/182 welds less than that used previously (e.g., WCAP-17262, Revision 1), explain the basis for the change.

2. Discuss a relevant crack growth analysis to confirm that the crack growth from the leakage crack to the critical crack in the Alloy 82/182 welds will take a sufficient time to detect leakage and shut down the reactor safely.

RAI 4.7.3-2 (eRAI Letter #146, Question #239)

Request:

Section 7.0 of WCAP-11163, Revision 2 indicates that an elastic-plastic facture mechanics analysis is performed for cast austenitic stainless steel locations considering applied J-integral values as a driving force for fracture in the LBB TLAA.

The Ramberg-Osgood parameters are used in the applied J-integral estimations (i.e., , n, o and o in /o = (/o) + (/o)n as addressed in NUREG-1061, Volume 3, Section A2.3.1).

These parameters may be time-dependent in the LBB TLAA. If so, discuss how these time-dependent parameters are calculated as part of the LBB analysis. In addition, provide the parameter values used in the analysis.

RAI 4.7.3-3 (eRAI Letter #146, Question #240)

Request:

SRLA Section 4.7.3 addresses the LBB TLAA, including the Alloy 82/182 welds that are susceptible to PWSCC. As discussed in SLRA Section B2.1.5, cracking due to PWSCC in nickel alloy welds is managed by performing the inspections in accordance with ASME Code Case N-770 as incorporated by reference in 10 CFR 50.55a, "Codes and standards."

In contrast, the applicant (Dominion Energy) dispositioned the LBB TLAA in accordance with 10 CFR 54.21(c)(1)(ii) but not in accordance with 10 CFR 54.21(c)(1)(iii) that includes the performance of aging management activities in connection with the TLAA. Explain the basis for the dispositioning of the TLAA (not including aging management activities) even though cracking due to PWSCC in the Alloy 82/182 welds within the scope of LBB TLAA is managed by the inspections in accordance with ASME Code Case N-770 as required by 10 CFR 50.55a.