W3F1-2016-0075, Responses to Request for Additional Information Set 6 Regarding the License Renewal Application

Responses to Request for Additional Information Set 6 Regarding the License Renewal Application

ML16342C491
Person / Time
Site:	Waterford
Issue date:	12/07/2016
From:	Chisum M Entergy Operations
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
W3F1-2016-0075
Download: ML16342C491 (46)

Text

Entergy Operations, Inc.

17265 River Road Killona, LA 70057-3093 Tel 504-739-6660 Fax 504-739-6698 mchisum@entergy.com Michael R. Chisum Site Vice President Waterford 3 W3F1-2016-0075 December 7, 2016 U.S. Nuclear Regulatory Commission Attn: Document Control Desk Washington, DC 20555-0001

SUBJECT:

Responses to Request for Additional Information Set 6 Regarding the License Renewal Application for Waterford Steam Electric Station, Unit 3 (Waterford 3)

Docket No. 50-382 License No. NPF-38

REFERENCES:

1. Entergy letter W3F1-2016-0012 License Renewal Application, Waterford Steam Electric Station, Unit 3 dated March 23, 2016.

2. NRC letter to Entergy Requests for Additional Information for the Review of the Waterford Steam Electric Station, Unit 3, License Renewal Application - Set 6 dated November 7, 2016.

Dear Sir or Madam:

By letter dated March 23, 2016, Entergy Operations, Inc. (Entergy) submitted a license renewal application (Reference 1).

In letter dated November 7, 2016 (Reference 2), the NRC staff made a Request for Additional Information (RAI) Set 6, needed to complete its review. Enclosure 1 provides the responses to the Set 6 RAIs.

This letter adds License Renewal Commitment 33 as shown in Enclosure 2. If you require additional information, please contact the Regulatory Assurance Manager, John Jarrell, at 504-739-6685.

I declare under penalty of perjury that the foregoing is true and correct. Executed on December 7, 2016.

Enclosures:

1. Set 6 RAI Responses - Waterford 3 License Renewal Application

2. Commitment 33

W3F1-2016-0075 Page 2 of 2 cc: Kriss Kennedy RidsRgn4MailCenter@nrc.gov Regional Administrator U. S. Nuclear Regulatory Commission Region IV 1600 E. Lamar Blvd.

Arlington, TX 76011-4511 NRC Senior Resident Inspector Frances.Ramirez@nrc.gov Waterford Steam Electric Station Unit 3 Chris.Speer@nrc.gov P.O. Box 822 Killona, LA 70066-0751 U. S. Nuclear Regulatory Commission Phyllis.Clark@nrc.gov Attn: Phyllis Clark Division of License Renewal Washington, DC 20555-0001 U. S. Nuclear Regulatory Commission April.Pulvirenti@nrc.gov Attn: Dr. April Pulvirenti Washington, DC 20555-0001 Louisiana Department of Environmental Ji.Wiley@LA.gov Quality Office of Environmental Compliance Surveillance Division P.O. Box 4312 Baton Rouge, LA 70821-4312

Enclosure 1 to W3F1-2016-0075 Set 6 RAI Responses Waterford 3 License Renewal Application to W3F1-2016-0075 Page 2 of 42 RAI 3.5.1.93-1

Background:

Section 54.21(a)(3) of 10 CFR requires the 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. As described in SRP-LR, an applicant may demonstrate compliance with 10 CFR 54.21(a)(3) by referencing the GALL Report and when evaluation of the matter in the GALL Report applies to the plant.

SRP-LR Table 3.5-1, item 93, recommends that galvanized steel, aluminum, or stainless steel support members, welds, bolted connections, and support anchorage exposed to an air outdoor environment be managed for loss of material due to pitting and crevice corrosion by the Structures Monitoring Program. Per the GALL Report, this item relates to supports for cable trays, conduit, HVAC (heating, ventilating, and air conditioning) ducts, tubetrack, instrument tubing, and non-ASME Code piping and components, or to supports for emergency diesel generator, HVAC system components, and other miscellaneous mechanical equipment.

SRP-LR Table 3.5-1, item 91, addresses steel support members, welds, bolted connections, and support anchorage for ASME Code Class 1, 2, 3 and MC supports and recommends the ASME Code Section XI, Subsection IWF Program.

LRA Table 3.5.2-4 identifies an AMR result which states that for stainless steel structural bolting exposed to an air outdoor environment, the Inservice Inspection - IWF Program will be used to manage loss of material. This AMR line item cites generic note E, indicating that the material, environment, and aging effect is consistent with the GALL Report but a different AMP is credited.

Issue:

Based on the information provided in the LRA, it is not clear whether the AMR line item in LRA Table 3.5.2-4 addresses structural bolting for ASME Code Section XI, Subsection IWF component supports (e.g. Class 1, 2, 3, and metal containment piping and components and their associated supports) or non-ASME Code supports as indicated by the reference to GALL Report item III.B2.TP-6. The scope of the Inservice Inspection - IWF Program described in LRA Section B.1.6 appears to be limited to ASME Code Class 1, 2 and 3 piping and component supports, whereas the components associated with SRP-LR Table 3.5-1, item 93, are intended for non-ASME Code piping and components.

Request:

1. For the LRA Table 3.5.2-4 AMR line item associated with SRP-LR Table 3.5-1, item 93, which credits the Inservice Inspection - IWF Program to manage loss of material, clarify whether the stainless steel structural bolting is associated with ASME Code Section XI, Subsection IWF components or non-ASME Code component supports.

2. If the stainless steel structural bolting is for non-ASME Code related component supports, clarify if the bolting is within the scope of the Inservice Inspection - IWF Program described in LRA Section B.1.6, and how the aging effects will be adequately managed.

to W3F1-2016-0075 Page 3 of 42 Waterford 3 Response

1. In LRA Table 3.5.2-4, the AMR line item for stainless steel structural bolting that references SRP-LR Table 3.5-1, item 93, and credits the Inservice Inspection - IWF Program to manage loss of material is associated with ASME Code Section XI, Subsection IWF components. For clarification the component line item for structural bolting has been revised to reflect a comparison to NUREG-1800 Table 3.5.1, item 86 as shown below.

2. The stainless steel structural bolting is for ASME Code related components as described in response to part 1 above.

LRA revisions follow. Additions are shown with underline and deletions with strikethrough.

Table 3.5.2-4: Bulk Commodities Structure and/or Aging Effect Aging Component or Intended Requiring Management NUREG-1801 Table 1 Commodity Function Material Environment Management Program Item Item Notes Structural bolting SRE, SSR Stainless Air - outdoor Loss of ISI-IWF III.B2.TP-6 3.5.1-93 E A steel material III.B.1.1.TP-235 3.5.1-86 III.B.1.2.TP-235 to W3F1-2016-0075 Page 4 of 42 RAI 3.5.1.79-1

Background

Section 54.21(a)(3) of 10 CFR requires the 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. As described in SRP-LR, an applicant may demonstrate compliance with 10 CFR 54.21(a)(3) by referencing the GALL Report and when evaluation of the matter in the GALL Report applies to the plant.

SRP-LR Table 3.5-1, item 79, recommends that steel piles exposed to a groundwater/soil environment be managed for loss of material due to corrosion by the Structures Monitoring Program. Per the SRP-LR, this line item is associated with GALL Report item III.A3.TP-219 for structures and components supports.

LRA Table 2.4-3 lists the steel piles component as subject to aging management review with an intended function to support criterion (a)(3) equipment. LRA Table 3.5.1, item 3.5.1-79 states that steel piles exposed to groundwater and/or soil is not applicable because WF3 has no steel piles subject to the listed aging effects.

However, LRA Table 3.5.2-3 identifies one AMR item associated with steel piles exposed to soil as having no aging effects requiring management. This AMR item cites generic note I to state that this aging effect in the GALL Report is not applicable, and plant-specific note 501, page 3.5-49, which states:

Steel piles driven into undisturbed soils are unaffected by corrosion. Where steel piles are driven into disturbed soils, operating experience has shown that only minor to moderate corrosion has occurred that would not significantly affect the performance of the component intended function during the license renewal term. The steel piles are steel casings used as forms for the concrete inside the steel piles. The concrete inside the steel casing is not susceptible to degradation that could impair the ability of the concrete to perform its intended function. Therefore, no aging management is required.

Issue:

The staff noted inconsistencies between the AMR line item associated with steel piles in LRA Table 3.5.2-3, the LRA disposition of Table 3.5.1 item 3.5.1-79, and the intended function identified in LRA Table 2.4-3. LRA Table 2.4.3 dispositions the steel piles as having an intended function of support for Criterion 10 CFR 54.4(a)(3) equipment; LRA Table 3.5.1, item 3.5.1-79 states that WF3 has no steel piles subject to the loss of material due to corrosion aging effect; and plant-specific note number 501 from LRA Table 3.5.2-3 identifies the steel piles as experiencing an aging effect of minor to moderate corrosion but dispositions them as not requiring aging management due to being steel casings that are used as forms for the concrete (which is not susceptible to degradation) inside the steel piles. The staff also noted that plant-specific note number 501 does not provide a technical basis (e.g. analysis of degradation rate and expected degradation during the period of extended operation) to support the conclusion that no aging management is required for steel piles with ongoing corrosion or for the concrete inside the steel casings.

Based on the information provided in the LRA, the staff is not clear (1) whether the steel piles or steel casing are within the scope of license renewal, and (2) whether the AMR line item in LRA Table 3.5.2-3 and associated line item 3.5.1-79 in LRA Table 3.5.1, are consistent with the GALL Report recommendation from line item III.A3.TP-219 to ensure that the aging effects of loss of material due to corrosion is adequately managed for the period of extended operation.

to W3F1-2016-0075 Page 5 of 42 Request:

1. Clarify if steel piles or steel casings are within the scope of license renewal and the intended function that needs to be maintained during the period of extended operation.

2. If steel piles are within the scope of license renewal, describe how the aging effects of loss of material due to corrosion in steel piles exposed to a groundwater/soil environment will be adequately managed so that the intended function will be maintained consistent with the current licensing basis for the period of extended operation. Otherwise, provide the technical justification for the exception to the GALL Report recommendation.

3. Clarify any inconsistency between LRA Table 3.5.1, item 3.5.1-79, and LRA Table 3.5.2-3 line item associated with steel piles to be consistent with the response to the above request.

Waterford 3 Response

1. The steel casings, filled internally with concrete, are within the scope of license renewal as identified in Waterford 3 (WF3) license renewal application (LRA) Table 2.4-3 and Table 3.5.2-3 to provide structural support of the fire water tanks, which are in-scope for fire protection in accordance with 10 CFR 54.4(a)(3).

2. The Waterford 3 steel casings are within the scope of LR as discussed in response to part 1 above. As shown in the LRA Table 2.4-3 the steel casings are subject to aging management review. Inspections of the fire water tanks and their foundations will be able to detect potential degradation, if any, in the tank foundation that degraded steel piles might cause (e.g., settlement). However, as shown in LRA Table 3.5.2-3 and associated note 501, they do not have aging effects requiring management. Industry operating experience, reported in EPRI 1015078 Plant Support Engineering: Aging Effects for Structures and Structural Components (Structural Tools), has shown that the type and amount of corrosion observed on steel pilings driven into undisturbed natural soil, regardless of the soil characteristics and properties, is not sufficient to significantly affect the strength of pilings as load bearing structures. The data also indicate that undisturbed natural soils are so deficient in oxygen at levels a few feet below the surface, or below the water table, that steel piles are not appreciably affected by corrosion. Because steel piles driven in undisturbed soils have been shown to be unaffected by corrosion and those driven in disturbed soil have experienced only minor to moderate corrosion, loss of material due to corrosion is not an aging effect requiring management for steel piles. Also, industry operating experience has shown that the concrete inside steel pipe piles is not susceptible to degradation that could impair the ability of the concrete to perform its intended function because the strength capacity of the laterally constrained concrete is not sensitive to degradation of the steel casing. The Waterford 3 in-scope concrete piles with steel pipe casings driven into the soil do not have aging effects requiring management for the PEO.

3. As discussed in responses to part 1 and 2 above, Waterford 3 steel piles are in-scope of license renewal and subject to aging management review, but have no aging effects requiring management as shown in LRA Table 2.4-3, 3.5.2-3 and 3.5.1 item 79. However, LRA Table 3.5.1 item 3.5.1-79 discussion has been revised to provide additional clarification to show consistency with Tables 2.4-3 and 3.5.2-3.

LRA revisions are as follows. Additions are shown with underline and deletions with strikethrough.

to W3F1-2016-0075 Page 6 of 42 Table 3.5.1: Structures and Component Supports Aging Aging Effect/ Management Further Evaluation Item Number Component Mechanism Program Recommended Discussion 3.5.1-79 Steel Loss of material Structures No Not applicable. WF3 has components: due to corrosion Monitoring no steel piles subject to piles Program the listed aging effect; therefore this line item was not used. Waterford 3 in-scope steel piles are not subject to this aging effect.

Industry operating experience has shown that steel piles driven in subgrade experience insignificant degradation and that loss of material due to corrosion is not an aging effect requiring management.

to W3F1-2016-0075 Page 7 of 42 RAI 3.5.1.62-1 Section 54.21(a)(3) of 10 CFR requires the 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. As described in SRP-LR, an applicant may demonstrate compliance with 10 CFR 54.21(a)(3) by referencing the GALL Report when evaluation of the matter in the GALL Report applies to the plant.

SRP-LR Table 3.5.1, item 62 recommends GALL Report AMP XI.S7, RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants, to manage the aging effects of loss of material and changes in material properties for wooden piles exposed to groundwater or soil. The GALL Report AMP recommends periodic visual inspection of the accessible portions of the wooden piles. No additional recommendations are provided for inaccessible portions of wooden piles; however, the guidance assumes at least a portion of the pile is available for inspection.

Issue:

WF3 LRA Table 3.5.1, item 3.5.1-62, notes that the Structures Monitoring Program manages the listed aging effects for the wooden piles associated with the fire pump house. LRA Section 2.4.3 notes that the piles are driven into the subgrade and covered by the fire pump house concrete foundation.

The Structures Monitoring Program includes equivalent periodic visual inspections so proposing to use the Structures Monitoring Program instead of the GALL Report recommended AMP is acceptable. However, the staff is not clear how the visual inspection program will adequately manage the effects of aging for the wooden piles if none of the piles are accessible for inspection.

Request:

Explain how the Structures Monitoring program will manage the wooden piles for the aging effects of loss of material and changes in material properties so that the intended function will be maintained for the period of extended operation, or propose a new aging management approach.

Waterford 3 Response As shown on Waterford 3 (WF3) design drawings, the treated wooden piles are covered by the fire pump house concrete foundation and therefore are inaccessible for visual inspections. The wooden piles are not exposed to air-outdoor environment. Industry operating experience has shown that treated wood pilings are not subject to significant aging when driven into groundwater/soil. Therefore, degradation due to the effects of aging is not expected. Nevertheless, Waterford 3 Structures Monitoring Program will be used to manage potential aging effects of loss of material and changes in material properties of wooden pilings during the period of extended operation. Inspections of the fire pump house will be able to detect degradation, if any, in the structure that degraded wood piles might cause (e.g., settlement).

For clarification, Table 3.5.2-3 of the Waterford 3 license renewal application is revised as follows. Additions are shown with underline and deletions with strikethrough.

to W3F1-2016-0075 Page 8 of 42 Table 3.5.2-3: Turbine Building and Other Structures Structure and/or Aging Effect Aging NUREG-Component or Intended Requiring Management 1801 Table Commodity Function Material Environment Management Program Item 1 Item Notes Error!

Refer Loss of material ence Wooden piles Treated Change in Structures III.A6.TP 3.5.1-SNS Soil sourc (inaccessible) wood material monitoring -223 62 e not properties found

.G to W3F1-2016-0075 Page 9 of 42 RAI 3.5.1.56-1 Section 54.21(a)(3) of 10 CFR requires the 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. As described in SRP-LR, an applicant may demonstrate compliance with 10 CFR 54.21(a)(3) by referencing the GALL Report when evaluation of the matter in the GALL Report applies to the plant.

SRP-LR Table 3.5-1, item 56 recommends GALL Report AMP XI.S7, RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants, to manage the aging effect of loss of material due to abrasion and cavitation for concrete exposed to flowing water.

WF3 LRA Table 3.5.1 Item 3.5.1-56, notes that the SRP line item does not apply because the item is specific to Group 6 components and WF3 has not identified components for this grouping.

Issue:

WF3 has concrete structures exposed to flowing water (e.g., structures associated with the ultimate heat sink) that could potentially experience loss of material due to abrasion or cavitation, and which may require aging management to maintain intended function. The staff is not clear regarding the technical basis for not managing the aging effect of loss of material due to abrasion and cavitation for the WF3 concrete structures exposed to flowing water.

Request:

Provide a technical justification explaining why concrete structures exposed to flowing water do not require aging management for loss of material due to abrasion or cavitation; otherwise, update the LRA to address this aging effect.

Waterford 3 Response As reported in EPRI 1015078, Plant Support Engineering: Aging Effects for Structures and Structural Components (Structural Tools), abrasion and cavitation may cause a loss of material in concrete structures and structural members that are continuously exposed to flowing water containing abrasives and water velocities greater than 40 feet per second for open channels and 25 feet per second for closed conduit flow.

The concrete structures subject to aging management review and exposed to flowing water at Waterford 3 (WF3) are the wet cooling tower basins. These concrete basins, associated with the Waterford 3 ultimate heat sink, normally contain standing water. When a wet cooling tower is in service, flow is distributed throughout the basin resulting in low flow rates of less than 10 feet per second. Because the basins are not exposed to continuous flowing water with velocities in excess of 40 feet per second, loss of material due to abrasion and cavitation is not an aging effect requiring management. Waterford 3 operating experience has not indicated that loss of material due to abrasion and cavitation is an aging effect requiring management.

For clarification, Waterford 3 license renewal application Table 3.5.1, Item 3.5.1-56, is revised as follows.

Additions are shown with underline and deletions with strikethrough.

to W3F1-2016-0075 Page 10 of 42 Table 3.5.1: Structures and Component Supports Aging Aging Effect/ Management Further Evaluation Item Number Component Mechanism Program Recommended Discussion Concrete: Loss of material Regulatory Guide No This NUREG 1801 line item 3.5.1-56 exterior above- due to abrasion; 1.127, Inspection is specific to Group 6 and below- cavitation of Water-Control components. WF3 has not grade; Structures identified components for this foundation; Associated with grouping. Therefore Loss of interior slab Nuclear Power material due to abrasion and Plants or the cavitation is not an aging FERC/US Army effect requiring management Corp of Engineers for concrete components of dam inspections the wet cooling tower basins and maintenance since the water in the basins programs. has low flow rates that would not cause concrete degradation.

to W3F1-2016-0075 Page 11 of 42 RAI 3.5.1.52-1

Background:

Section 54.21(a)(3) of 10 CFR requires the 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. As described in SRP-LR, an applicant may demonstrate compliance with 10 CFR 54.21(a)(3) by referencing the GALL Report and when evaluation of the matter in the GALL Report applies to the plant.

SRP-LR Table 3.5-1, item 52, recommends that steel tank liners exposed to standing water be managed for cracking due to stress corrosion cracking (SCC) and loss of material due to pitting and crevice corrosion by a plant-specific program.

Issue:

The staff needs additional information with regards to management of the loss of material due to pitting and crevice corrosion aging effect. LRA Table 3.5.2-1 AMR items associated with table 1 item 3.5.1-52 address stainless steel safety injection system (SIS) sump screens and strainers, reactor cavity seal ring and hatches, cooling tower fill/miss eliminators, condensate storage pool liner plate, refueling water storage pool liner plate, vortex breakers/screens/strainers, and reactor building liner plate exposed to fluid environment. The applicant cited note E, indicating it proposes to use a program other than the GALL Report-recommended program. For these structural components, the applicant stated it will use the Structures Monitoring Program (as opposed to the GALL Report recommendation of a plant-specific program) to manage the aging effect of loss of material for these components.

The staff reviewed the Structures Monitoring Program AMP and noted that the program uses periodic visual inspections to manage applicable aging effects for LRA Table 3.5.2-1 components. For the components that are submerged in a fluid environment, it is not clear how the visual inspections performed under the Structures Monitoring Program will be capable of managing the aging effect of loss of material if the components are submerged in a fluid environment and not accessible for visual inspection.

Request:

State how the Structural Monitoring Program will adequately manage the aging effect of loss of material due to pitting and crevice corrosion for stainless steel components associated with table 3.5.1, item 52 that are exposed to a fluid environment and not accessible for visual inspection.

Waterford 3 Response Waterford 3 (WF3) Structures Monitoring Program (SMP) as described in the license renewal application (LRA)

Section B.1.38 with enhancements will manage loss of material due to pitting and crevice corrosion of submerged stainless steel (SS) components associated with LRA table 3.5.1-52. Specifically, the enhancement identified in the LRA Section B.1.38, Element 4 Detection of Aging Effects, will ensure that components that are exposed to a fluid environment and not easily accessible for visual inspection will be inspected at least once every 5 years. The program includes provisions for use of appropriate tools such as flashlights, cameras and other appropriate inspection aids (e.g., divers) to ensure access and proper visual inspections of components exposed to fluid environments.

to W3F1-2016-0075 Page 12 of 42 RAI 3.5.2.2.2.1-1

Background:

Section 54.21(a)(3) of the10 CFR requires the 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. As described in SRP-LR, an applicant may demonstrate compliance with 10 CFR 54.21(a)(3) by referencing the GALL Report and when evaluation of the matter in the GALL Report applies to the plant.

LRA Section 3.5.2.2.2.1, item 4, associated with LRA Table 3.5.1, item 3.5.1-47, addresses Concrete (inaccessible areas): exterior above- and below-grade; foundation of Groups 1- 5 and 7-9 structures exposed to groundwater for aging effects increase in porosity and permeability, and loss of strength due to leaching of calcium hydroxide and carbonation. This LRA section states that WF3 Groups 1-5 and 7-9 concrete structures are designed and constructed in accordance with ACI 318 (1963 and/or 1971 editions) using materials conforming to ACI and ASTM standards (e.g., ASTM C150, Type II for cement, ASTM C33 for aggregate) to produce dense well-cured durable concrete having low permeability consistent with the guidance and recommendations in ACI 201.2R-77. The LRA section further states that below-grade inaccessible concrete areas of Groups 1-5 and 7-9 concrete structures are exposed to groundwater, which is considered equivalent to a flowing water environment, and therefore, increase in porosity and permeability, and loss of strength due to leaching of calcium hydroxide and carbonation is an applicable aging effect for the below-grade inaccessible concrete areas at WF3 that will be managed by the Structures Monitoring Program.

The criteria in SRP-LR Section 3.5.2.2.2.1, item 4, provides that increase in porosity and permeability, and loss of strength due to leaching of calcium hydroxide and carbonation could occur in below-grade inaccessible areas of Group 1-5, and 7-9 concrete structures exposed to water-flowing environment. The SRP-LR also states that further evaluation is required if leaching is observed in accessible areas that impact intended functions. The related review procedure in SRP-LR 3.5.3.2.2.1, item 4, and the GALL Report AMR line items associated with SRP-LR Table 3.5.1, item 3.5.1-47, also note that further evaluation is required to determine if a plant-specific aging management program is needed to manage increase in porosity and permeability due to leaching of calcium hydroxide and carbonation of inaccessible concrete areas, and that a plant-specific aging management program is not required if (1) there is evidence in the accessible areas that the flowing water has not caused leaching and carbonation, or (2) evaluation determined that the observed leaching of calcium hydroxide and carbonation in accessible areas has no impact on the intended function of the concrete structure.

GALL Report Table IX.D defines water-flowing environment as Water that is refreshed; thus, it has a greater impact on leaching and can include rainwater, raw water, ground water, or water flowing under a foundation.

LRA Table 3.0-2 Service Environments for Structural Aging Management Reviews defines exposed to fluid environment for structures at WF3 as raw water or treated water, and states that it includes corresponding NUREG-1801 environments: ground water, treated water, treat water > 140 oF, water-flowing, and water-standing.

to W3F1-2016-0075 Page 13 of 42 Issue:

In its review of LRA AMP B.1.38 Structures Monitoring, the staff noted that the program does not include any plant-specific enhancement to specifically address the aging effects of increase in porosity and permeability, and loss of strength due to leaching of calcium hydroxide and carbonation for inaccessible areas, so it appears that a plant-specific AMP was deemed not necessary. In addition, the further evaluation in LRA Section 3.5.2.2.2.1, item 4, is silent related to the WF3 operating experience with regard to the aging effects of leaching and carbonation at WF3. Contrary to the criteria in the SRP-LR, the applicant did not state it would be using a plant-specific program or a Structures Monitoring Program enhancement and there is no discussion of (1) an evaluation to determine whether there is evidence in the accessible areas that the flowing water has not caused leaching and carbonation; or (2) an evaluation that determined that the observed leaching of calcium hydroxide and carbonation in accessible areas has no impact on the intended function of the concrete structure. Therefore, the staff finds that sufficient information is not provided in the further evaluation in LRA Section 3.5.2.2.2.1, item 4, for the staff to determine if the applicant has met the further evaluation criteria of SRP-LR stated above with regard to whether a plant-specific program is needed to manage the aging effects.

Additionally, in its review of components associated with item 3.5.1-47, the staff also finds that there are no Table 2 aging management review (AMR) line items identified in LRA Tables 3.5.2-1 through 3.5.2-4 for LRA Table 3.5.1, item 3.5.1-47 (and corresponding GALL Report line items) that would indicate that the aging effects will be appropriately managed for the applicable components.

Request:

(1) Address the further evaluation criteria in SRP-LR Section 3.5.2.2.2.1, item 4, described in the Background Section and justify whether or not a plant-specific program is necessary to manage the aging effects related to SRP-LR Table 3.5.1, item 47. Provide information describing whether or not WF3 has observed leaching of calcium hydroxide and carbonation in accessible concrete areas subject to a exposed to fluid environment, which by definition in LRA Table 3.0-2 includes the applicable GALL Report water-flowing environment, its evaluation for impact on intended functions, and demonstrate how it would be adequately managed in inaccessible concrete areas.

(2) Provide justification for not including Table 2 AMR line items in LRA Tables 3.5.2-1 through 3.5.2-4 for LRA Table 3.5.1, item 3.5.1-47 (and corresponding GALL Report line items), which the applicant claimed to be applicable.

Waterford 3 Response

1. A 2011 report identified a condition involving mineral deposits on the surface of a concrete ceiling in the reactor auxiliary building. Inspections performed under the Waterford 3 Structures Monitoring Program (SMP) identified the condition, which was noted as potential leaching of calcium hydroxide. However, the location of the deposits was not in an area exposed to a ground water environment. The condition was evaluated and determined to have no impact on the structures intended function. In the next SMP inspection of the area, no indications of leaching were observed. Waterford 3 operating experience has not identified leaching of calcium hydroxide and carbonation for accessible structures exposed to ground water or flowing water environments. The operating experience provides reasonable assurance that structural integrity of concrete in inaccessible areas is also not impacted. Leaching of calcium hydroxide and carbonation is not an aging effect requiring management for Waterford 3 concrete structures exposed to a to W3F1-2016-0075 Page 14 of 42 ground water / soil environment

2. To align with the response to Part 1 above, the further evaluation discussion in LRA Section 3.5.2.2.2.1, Item 4, is revised to clarify that leaching of calcium hydroxide and carbonation is not an aging effect requiring management for concrete structures exposed to ground water/ soil environment. Also LRA Table 3.5.1, Item 13 is revised to delete reference to LRA Table 3.5.1, Item 47. It should be noted that Group 1 and 4 structures are founded on the nuclear plant island structure and are not subject to the ground water /

soil environment.

LRA revisions are as follows. Additions are shown with underline and deletions with strikethrough.

3.5.2.2.2.1 Aging Management of Inaccessible Areas

4. Increase in Porosity and Permeability, and Loss of Strength Due to Leaching of Calcium Hydroxide and Carbonation of Below-grade Inaccessible Concrete Areas of Groups 1-5 and 7-9 Structures The Groups 1-5 and 7-9 Structures at WF3 are designed in accordance with ACI 318-63 and/or ACI 318-71 and constructed in accordance with the recommendations in ACI 318-63 and ACI 318-71 using ingredients/materials conforming to ACI and ASTM standards. The concrete mix uses Portland cement conforming to ASTM C150, Type II. Concrete aggregates conform to the requirements of ASTM C33. Materials for concrete used in WF3 concrete structures and components were specifically investigated, tested, and examined in accordance with pertinent ASTM standards. The type and size of aggregate, slump, cement and additives have been established to produce durable concrete in accordance with ACI. Cracking is controlled through proper arrangement and distribution of reinforcing steel. Concrete structures and concrete components are constructed of a dense, well-cured concrete with an amount of cement suitable for strength development and achievement of a water-to-cement ratio that is characteristic of concrete having low permeability. This is consistent with the recommendations and guidance provided by ACI 201.2R-77. The below-grade inaccessible concrete areas of Groups 1-5 and 7-9 concrete structures at WF3 are exposed to groundwater which is considered equivalent to a flowing water environment.

WF3 operating experienced has not identified leaching of calcium hydroxide and carbonation of below-grade accessible concrete structures exposed to a ground water environment. Therefore, increase in porosity and permeability, and loss of strength due to leaching of calcium hydroxide and carbonation in below-grade inaccessible concrete areas is not an applicable aging effect requiring management for the inaccessible concrete of WF3 Groups 1-5 and 7-9 concrete structures. The Structures Monitoring Program manages increase in porosity and permeability, and loss of strength due to leaching of calcium hydroxide and carbonation in below-grade inaccessible concrete areas of WF3 Groups 1-5 and 7-9 concrete structures.

to W3F1-2016-0075 Page 15 of 42 Table 3.5.1: Structures and Component Supports Aging Aging Effect/ Management Further Evaluation Item Number Component Mechanism Program Recommended Discussion 3.5.1-13 Concrete Increase in Further evaluation is Yes, if leaching is WF3 is a PWR with free-(inaccessible porosity and required to observed in standing SCV supported on a areas): permeability; loss determine if a plant- accessible areas that common rigid reinforced basemat, of strength due to specific aging impact intended concrete foundation structure Concrete leaching of calcium management function for the NPIS. The SCV (inaccessible hydroxide and program is needed. structures base foundation areas): dome; carbonation (basemat) is integral with the wall; basemat base foundation of the shield building and protected from the external environments by the shield building's base foundation. Since the WF3 primary containment concrete foundation (basemat) is inaccessible, it is exempted from inspection and the ISI-IWL program does not apply.

Accordingly, WF3 does not have an ISI-IWL program.

The listed aging effects are addressed by Item 3.5.1-47.

For further evaluation, see Section 3.5.2.2.1.9.

to W3F1-2016-0075 Page 16 of 42 RAI 3.5.1.74-1

Background:

Section 54.21 (a)(3) of Title 10 of the Code of Federal Regulations (10 CFR) requires applicants to demonstrate that the effects of aging will be adequately managed so that intended function(s) will be maintained consistent with the current licensing basis (CLB) for the period of extended operation.

For aging management review (AMR) item 3.5.1-74 the Generic Aging Lessons Learned (GALL) Report recommends GALL Report aging management program (AMP) XI.S6, Structures Monitoring, to manage the aging effect of loss of mechanical function due to corrosion, distortion, dirt, debris, overload and wear for sliding support bearings and surfaces. The GALL Report states that components addressed under AMR item 3.5.1-74 include supports and anchorage for cable trays, conduit, heating, ventilation, and air-conditioning (HVAC) ducts, TubeTrack, instrument tubing, and non-ASME piping and components; and supports for emergency diesel generator, HVAC system components, and other miscellaneous mechanical equipment.

Issue:

For AMR item 3.5.1-74 in LRA Table 3.5.1, Containment, Structures and Component Supports, NUREG-1801, the applicant stated that GALL Report AMRs referencing item 3.5.1-74 are associated with Lubrite plates and Lubrite plates are not subject to aging management because the listed aging mechanisms are event driven and typically can be avoided through proper design. Therefore, the applicant stated that the aging effects for these components were not applicable.

The staff disagrees that the aging mechanisms are solely event driven. Even though Lubrite bearings are characterized as maintenance-free, they can still be subject to the aging effects of loss of material due to wear or corrosion, debris, or dirt that could lead to a loss of intended function if the aging effects are not detected and adequately managed during the period of extended operation (PEO). GALL Report AMP XI.S6 recommends that the potential aging effects for Lubrite be managed by performing periodic examination under the Structures Monitoring Program. Absent an inspection of Lubrite plates, it is not clear how the potential aging effects will be identified and adequately managed so that intended function(s) will be maintained consistent with the CLB during the PEO.

Request:

1) Provide additional basis to support the determination that the aging effects of loss of material due to wear or corrosion, debris, or dirt that could lead to a loss of intended function are not applicable to Lubrite plates and justification for not performing periodic inspections to identify aging effects during the period of extended operation.

2) If it is determined that the components will be inspected, state whether the inspections will be consistent with the GALL Report recommendation for periodic inspection under the Structures Monitoring Program.

Waterford 3 Response

1. Waterford 3 (WF3) has not identified Lubrite sliding surfaces that are applicable to NUREG-1801 Table 3.5.1 Item 74 which pertains to supports and anchorage for cable trays, conduit, heating, ventilation, and air-conditioning (HVAC) ducts, TubeTrack, instrument tubing and non-ASME piping and components; and supports for emergency diesel generator, HVAC system components, and other miscellaneous mechanical equipment. Waterford 3 does have Lubrite plates associated with the reactor coolant system, but they are addressed in the LRA, Table 3.5.1, Item 75. Industry and plant operating experience has not identified to W3F1-2016-0075 Page 17 of 42 failure of components due to degradation of Lubrite sliding surfaces on component supports used in structural applications. Because Waterford 3 has not identified Lubrite sliding surfaces associated with components listed in this line item, no aging management review results are provided that are associated with Table 3.5.1, Item 74. Nevertheless, the Structures Monitoring Program (SMP) manages loss of material due to general corrosion of steel component supports that could lead to loss of mechanical function. The Waterford 3 SMP will ensure aging effects for the in-scope components including those listed in this line item are adequately managed during the period of extended operation (PEO) so that intended functions are maintained. For clarification LRA Table 3.5.1 item 74 has been revised to provide additional discussion consistent with this response.

2. As discussed in response to part 1 above, no Waterford 3 components have been identified associated with NUREG-1801, Table 3.5.1, item 74. Therefore, inspections of such components are not applicable.

LRA revisions follow. Additions are shown with underline and deletions with strikethrough.

Table 3.5.1: Structures and Component Supports Aging Aging Effect/ Management Further Evaluation Item Number Component Mechanism Program Recommended Discussion 3.5.1-74 Sliding Loss of Structures No . Lubrite plates are not support mechanical Monitoring subject to aging bearings; function due to Program management because the sliding corrosion, listed aging mechanisms support distortion, dirt, are event driven and surfaces debris, overload, typically can be avoided wear though proper design.

NUREG-1801 items referencing this item are associated with Lubrite, graphitic tool steel, Fluorogold and Lubrofluor, which have not been identified for WF3 components associated with this line item.

to W3F1-2016-0075 Page 18 of 42 RAI 4.6-1

Background:

Section 54.21 (c)(1) of 10 CFR requires the evaluation of time-limited aging analyses (TLAA) 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 period of extended operation; or (iii) the effects of aging on the intended function will be adequately managed for the period of extended operation. Section 4.6 of the SRP-LR states that if a plants code of record requires a fatigue analysis, then this analysis may be a TLAA and must be evaluated in accordance with 10 CFR 54.21(c)(1) to ensure that the effects of aging on the intended functions are adequately managed for the period of extended operation. SRP-LR acceptance criteria in Section 4.6.2.1.1.1 states that a TLAA is acceptable under 10 CFR 54.21(c)(1)(i) when the existing CUF calculations remains valid because the number of assumed cyclic loads will not be exceeded during the period of extended operation

[when compared to the extrapolation to 60 years of operation of the operating transients experienced to date].

License renewal application (LRA) Section 4.6, Containment Liner Plate, Metal Containments, and Penetrations Fatigue Analysis, states that, as described in FSAR Section 3.6.2.4, penetration bellows are designed for a minimum of 7,000 thermal cycles and 200 design seismic movement (cycles). The LRA Section 4.6 dispositioned the analysis of the penetration bellows in accordance with 10 CFR 54.21(c)(1)(i) by stating that these cycles are more than what these expansion joints will experience through the period of extended operation.

Issue:

Contrary to the SRP-LR acceptance criteria in Section 4.6.2.1.1.1, LRA Section 4.6 does not include the number of operating transient cycles experienced by the penetrations bellows to date, and their extrapolation to 60 years of operation, to demonstrate that the TLAA analyses meets 10 CFR 54.21(c)(1)(i). The staff requires this information to verify that the number of transients in the existing analyses will not be exceeded during the period of extended operation.

Request:

1. Provide information of the number of transient cycles experienced by the penetration bellows to date, and their extrapolation through the period of extended operation that would demonstrate that the TLAA analyses for the penetration bellows meets the criteria of 10 CFR 54.21(c)(1)(i).

Waterford 3 Response The design specification for the penetration bellows specified that they be qualified for 7000 cycles at maximum operating conditions and 200 cycles due to design seismic movements. The total thermal and pressure growth values utilized were from the containment vessel radial and vertical growth and the process line growth.

The combination of the maximum operating conditions does not occur during normal plant operation and the actual movement that is experienced is much smaller than movements during accident conditions. In determining the maximum operating condition, containment growth from post-accident pressurization and from post-accident thermal expansion was included. During containment pressurization for integrated leak rate testing, containment is not exposed to post-accident temperatures. Containment integrated leak rate tests have been performed less than 10 times over the life of the plant.

to W3F1-2016-0075 Page 19 of 42 The containment heatups are the result of reactor coolant system heatups. Reactor coolant system heatups are shown in LRA Table 4.3-1 with 70 cycles as of April 5, 2014 and a projected 60-year value of 144 cycles.

Operating basis earthquakes are shown in LRA Table 4.3-1, but no events have occurred.

The maximum operating conditions also include deflections caused by piping, guard pipe, and sleeve expansion due to elevated temperature. This deflection is added to the containment thermal and pressure growth values. The piping guard, pipe and sleeve growth is a small contributor to the maximum flexure. As identified in LRA Section 4.3.2-1, 7000 cycles will not be exceeded for non-Class 1 piping during 60 years of operation.

Since the combination of events required for the maximum operating conditions does not occur during normal plant operation and actual cycles experienced by the bellows are much less than 7000, the TLAA for the penetration bellows remains valid through the period of extended operation in accordance with 10 CFR 54.21(c)(1)(i).

to W3F1-2016-0075 Page 20 of 42 RAI 3.5.2.2.1.5-1

Background:

Section 54.21 (a)(3) of 10 CFR requires applicants to demonstrate that the effects of aging will be adequately managed so that intended functions will be maintained consistent with the current licensing basis for each structure and component subject to aging management review. As described in SRP-LR, an applicant may demonstrate compliance with 10 CFR 54.21(a)(3) by referencing the GALL Report and when evaluation of the matter in the GALL Report applies to the plant.

GALL Report item II.A3.C-13, associated with SRP-LR Table 3.5.1 item 9, addresses cumulative fatigue damage due to fatigue (only if current licensing basis (CLB) fatigue analysis exists) in penetration sleeves and penetration bellows (steel; stainless steel; dissimilar metal welds) exposed to an uncontrolled air-indoor or air-outdoor environment. GALL Report item II.A3.CP-37, associated with SRP-LR Table 3.5.1 item 27, addresses cracking due to cyclic loading (CLB fatigue analysis does not exist) in penetrations sleeves and penetration bellows (steel; stainless steel; dissimilar metal welds) exposed to an uncontrolled air-indoor or air-outdoor environment.

License renewal application (LRA) Table 3.5.1, item 3.5.1-9, states that Waterford 3 is consistent with the GALL Report for containment penetrations that experience significant cyclic loading. LRA Section 3.5.2.2.1.5, associated with Table 3.5.1 item 3.5.1-9, states that the evaluation of fatigue as a TLAA for the penetration bellows is addressed in LRA Section 4.6. The LRA also states that other containment mechanical penetration bellows located outside the containment building have been screened out of scope since they do not perform a pressure boundary function. LRA Table 3.5.1, item 3.5.1-27, also states that Waterford 3 does have a CLB fatigue analysis for penetration bellows, which is evaluated in Section 4.6.

FSAR section 3.8.2.1 describes the different types of containment penetrations (i.e. Type I - VI) and their design characteristics in order to maintain the desired containment integrity. The staff notes that, as described in FSAR section 3.8.2.1, each type of penetration relies on different components (e.g. bellows, flued heads, sleeves) to maintain their intended function.

Issue:

The staff finds that there are no Table 2 AMR line items identified in LRA Tables 3.5.2-1 Reactor Building -

Summary of Aging Management Evaluation for LRA Table 3.5.1, item 3.5.1-27, that would indicate that the aging effect of cracking due to cyclic loading for penetration sleeves and bellows (CLB fatigue analysis does not exist) will be appropriately managed for the applicable components. Considering the different types of penetrations described in FSAR section 3.8.2.1 and that there are no Table 2 items corresponding to SRP-LR item 3.5.1-27, the staff is not clear why the LRA Table 3.5.2-1 AMR results line item corresponding to Table 1, item 3.5.1-9, does not address penetrations sleeves, and how this component will be adequately managed for cumulative fatigue damage or cracking due to cyclic loading for the period of extended operation.

Request:

1. Clarify how the penetration sleeves will be adequately managed for cumulative fatigue damage through the period of extended operation. Otherwise, provide the technical basis for not addressing these component(s) in LRA Table 3.5.2-1 AMR results line items corresponding to Table 1, item 3.5.1-9.

2. Provide justification for not including Table 2 AMR line items in LRA Table 3.5.2-1 for SRP-LR Table 3.5.1, item 3.5.1-27, for penetration sleeves to manage cracking due to cyclic loading if CLB fatigue analysis does not exist for the component.

to W3F1-2016-0075 Page 21 of 42 Waterford 3 Response

1. As discussed in license renewal application (LRA) Section 4.6, the steel containment vessel (SCV) was designed to exhibit a general elastic behavior under accident and earthquake conditions of loading. No permanent deformation due to primary stresses is permitted in the design under any condition of loading.

Bellows are provided to accommodate movement of the penetration piping and sleeves due to thermal expansion. This prevents the imposition of loads on penetration sleeves due to differential movement between the SCV and the shield building, thereby minimizing loading on penetration sleeves. Therefore, cumulative fatigue damage is not an aging effect requiring management for the WF3 SCV penetration sleeves.

The only WF3 components in LRA Table 3.5.1, Item 9 with a CLB fatigue analysis are identified in LRA Table 3.5.2-1 as penetration bellows. The line item for penetration bellows in LRA Table 3.5.2-1 includes a reference to LRA Table 3.5.1, Item 9.

2. As stated in response to Part 1, cumulative fatigue damage is not an aging effect requiring management for the WF3 SCV penetration sleeves. Therefore, SRP-LR Table 3.5.1, Item 27, for penetration sleeves is not referenced in LRA Table 3.5.2-1. The discussion provided in LRA Table 3.5.1, Item 27 is revised to clearly state that the penetration sleeves are not subject to cyclic loading and as such, this NUREG-1801 item does not apply.

During preparation of this response, the need for a clarification to LRA Section 3.5.2.2.1.5 was identified.

LRA Section 3.5.2.2.1.5 states other containment mechanical penetration bellows located outside the containment building have been screened out of scope since they do not perform a pressure boundary function. While some bellows are part of the primary containment pressure boundary, others perform a pressure boundary function for secondary containment. LRA Section 4.6 includes evaluation of TLAAs for bellows in both the primary containment pressure boundary and the secondary containment pressure boundary.

LRA revisions follow. Additions are shown with underline and deletions with strikethrough.

3.5.2.2.1.5 Cumulative Fatigue Damage TLAAs are evaluated in accordance with 10 CFR 54.21(c) as documented in Section 4. By design, the WF3 steel containment vessel is not subject to a fatigue TLAA. Fatigue TLAAs for containment penetration bellows are evaluated as documented in Section 4.6. Other containment mechanical penetration bellows that are located outside the containment building have been screened out of scope because they do not perform a pressure boundary intended function and no fatigue analysis exists.

The NUREG-1801 BWR components, e.g., torus, suppression pool shell, vent line bellows, and unbraced downcomers, related to Mark I and II containments are not applicable to the WF3 PWR containment.

to W3F1-2016-0075 Page 22 of 42 Table 3.5.1: Structures and Component Supports Aging Effect/ Aging Management Further Evaluation Item Number Component Mechanism Program Recommended Discussion Penetration Cracking due to ISI (IWE) and 10 No WF3 is a PWR with a free-3.5.1-27 sleeves; cyclic loading CFR Part 50, standing SCV that does penetration (CLB fatigue Appendix J not have a CLB fatigue bellows, Steel analysis does not analysis. However, WF3 elements: exist) does have a CLB fatigue torus; vent analysis for penetration line; vent bellows, which is header; vent evaluated in Section 4.6.

line bellows; WF3 penetration sleeves downcomers, are not subject to cyclic Suppression loading. Penetration pool shell sleeves are equipped with bellows which minimizes loads on these components; therefore this aging effect does not require management.

Nevertheless, applicable penetration components are included in the Containment Inservice Inspection - IWE and Containment Leak Rate Programs.

to W3F1-2016-0075 Page 23 of 42 RAI 3.5.1.92-1

Background:

Section 54.21(a)(3) of 10 CFR requires the 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. As described in SRP-LR, an applicant may demonstrate compliance with 10 CFR 54.21(a)(3) by referencing the GALL Report and when evaluation of the matter in the GALL Report applies to the plant.

SRP-LR Table 3.5-1, item 92, recommends that steel support members; welds; bolted connections; support anchorage to building structure exposed to air - indoor, uncontrolled or air - outdoor environment be managed for loss of material due to general and pitting corrosion by the Structures Monitoring program.

Issue:

In LRA Table 3.5.2-4, the applicant used GALL Report identifier III.B2.TP-43 to indicate how it will manage steel fire hose reels exposed to air-indoor, uncontrolled, or air-outdoor environment. The applicant cited generic Note E, to note that it would manage these components using a different program than recommended by the GALL Report. For these structural components, the applicant stated it will use the Fire Water System Program (as opposed to the GALL Report recommendation of the Structures Monitoring Program) to manage the aging effect of loss of material for these components.

The staff noted that the Structures Monitoring Program, which is recommended by the GALL Report, includes periodic visual examinations of these components for loss of material. The staff reviewed the applicants Fire Water System program and did not identify fire hose reels as components to be managed under that program.

It was also not clear what inspection methods will be used and at what periodicity fire hose reels would be inspected to ensure these components are adequately managed for loss of material.

Request:

State how the Fire Water System Program will adequately manage the aging effect of loss of material due to general and pitting corrosion for steel fire hose reels associated with table 3.5.1, item 92 that are exposed to an air-indoor or air-outdoor environment.

Waterford 3 Response Waterford 3 Fire Water System (FWS) Program procedures specify visual inspections of fire hose reels for loss of material. The inspection frequency for fire hose reels is quarterly. As stated in the license renewal application (LRA) Table 3.5.2-4, the FWS Program described in LRA Section B.1.13 manages fire hose reels.

NUREG 1801 Section XI.M27; Fire Water System Program description states in part Components within the scope of water-based fire protection systems include items such as sprinklers, nozzles, fittings, valve bodies, fire pump casings, hydrants, hose stations, fire water storage tanks, fire service mains, and standpipes. WF3 includes the component fire reels in the definition for hose stations, therefore inspection of fire hose reels is included in this program and not in the Structures Monitoring Program described in LRA Section B.1.38. The FWS Program manages loss of material, flow blockage due to fouling, and loss of coating integrity for long-lived, passive water-based fire suppression system components using periodic flow testing and visual inspections. Therefore, the aging effect loss of material due to general and pitting corrosion for fire hose reels is adequately managed.

to W3F1-2016-0075 Page 24 of 42 RAI 3.5.2.2.2.1-2

Background:

Section 54.21(a)(3) of 10 CFR requires the 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. As described in SRP-LR, an applicant may demonstrate compliance with 10 CFR 54.21(a)(3) by referencing the GALL Report and when evaluation of the matter in the GALL Report applies to the plant.

SRP-LR Table 3.5-1, item 44, recommends that concrete exposed to soil for structures from all groups be managed for cracking and distortion due to increased stress levels from settlement using the Structures Monitoring Program. This line item is associated with several GALL Report items that address this material, environment and aging effect, including GALL Report item III.A1.TP-30 for Group 1 structures. The GALL Report identifies the PWR shield building as a Group 1 structure.

Issue:

In LRA Table 3.5-1, item 3.5.1-44, the applicant stated that all concrete will be managed for the aging effect of cracking and distortion due to increased stress levels from settlement, consistent with GALL Report recommendations. The LRA also states that this item is associated with further evaluation section 3.5.2.2.2.1 item 3, which states that Group 1-3 and 5-9 below-grade inaccessible concrete structures will be managed by the Structures Monitoring Program. LRA Section 3.5.2.2.1.1, associated with LRA Table 3.5.1-1, also credits inspections of the shield building concrete foundation to manage this aging effect for the primary containment foundation (which is integral with the shield building foundation). However, the LRA does not include any table 2 AMR line items associated with GALL Report item III.A1.TP-30 to manage cracking and distortion due to increased stress levels from settlement for concrete exposed to soil. Since there is no line item for the Group 1 shield building associated with GALL Report item III.A1.TP-30, it is unclear whether the shield building will be managed for this aging effect in accordance with the GALL Report recommendations.

Request:

State whether the concrete shield building foundation exposed to soil will be managed for cracking and distortion due to increased stress levels from settlement and provide any necessary associated table 2 information. If not, provide supporting justification.

Waterford 3 Response As described in WF3 license renewal application (LRA) Section 2.4.2, the shield building is directly founded on a common mat with the steel containment vessel (SCV) and supported on the nuclear plant island structure (NPIS). The NPIS is supported on a continuous reinforced concrete common foundation mat.. The foundation of the shield building does not come in contact with a soil environment. Therefore, the aging effect of cracking and distortion due to increased stress levels from settlement was not applied to the SCV and shield building concrete foundation individually since they rest on the common foundation mat of the NPIS. The common foundation mat of the NPIS is identified as susceptible to this aging effect and is included in LRA Table 3.5.2-2.

As shown in LRA Table 3.5.2-2, consistent with NUREG-1801 item III.A3.TP-30, the WF3 Structures Monitoring Program manages cracking and distortion due to increased stress levels from settlement of the NPIS common foundation mat.

to W3F1-2016-0075 Page 25 of 42 RAI 3.6.2.2.2-1

Background:

Section 54.21(a)(3) of 10 CFR requires the 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. As described in SRP-LR, an applicant may demonstrate compliance with 10 CFR 54.21(a)(3) by referencing the GALL Report, and when evaluation of the matter in the GALL Report applies to the plant.

Section 3.6.2.2.2 of SRP-LR, Reduced Insulation Resistance due to Presence of Any Salt Deposits and Surface Contamination, and Loss of Material due to Mechanical Wear Caused by Wind Blowing on Transmission Conductors states that: Loss of material due to mechanical wear caused by wind blowing on transmission conductors could occur in high-voltage insulators. The GALL Report recommends further evaluation of a plant-specific AMP to ensure that this aging effect is adequately managed.

In LRA 3.6.2.2.2, the applicant references SRP-LR for further evaluation of the above aging mechanisms and effects for high-voltage insulators. Table 3.6.1, line item numbers 3.6.1-2 and 3.6.1-3 identify the component as High voltage insulators composed of porcelain, malleable iron, aluminum, galvanized steel and cement.

The corresponding table 3.6.2 of the LRA for these two items identify the material as Porcelain, galvanized metal and cement.

Issue:

The staff noted an apparent discrepancy between LRA table 3.6.1 and table 3.6.2 in describing the material used for high-voltage insulators. Table 3.6.2 of the LRA is inconsistent with table 3.6.1 in that it has omitted malleable iron and aluminum from the list of materials that constitute high-voltage insulators. It is not clear whether this apparent discrepancy is based on a plant-specific evaluation that has determined a lack of such material for high-voltage insulators at Waterford 3 or is a result of inadvertent omission.

Request:

Clarify the apparent discrepancy between LRA table 3.6.1 items 3.6.1-2 and 3.6.1-3 and the two corresponding table 3.6.2 items that omitted malleable iron and aluminum from the materials listed for high-voltage insulators.

Waterford 3 Response LRA Table 3.6.1 lists the materials in NUREG-1800, Table 3.6-1. LRA Table 3.6.2-1 does not list a material that is not used in Waterford 3 electrical component types. Table 3.6.2-1 includes galvanized metal for high voltage insulators. Based on the Waterford 3 electrical screening and aging management review report, the materials at Waterford 3 for the metal portions (caps and pins) of the high-voltage insulators include various galvanized metals such as malleable iron, ductile iron and drop forged steel. The term galvanized metal used in LRA Table 3.6.2-1 includes malleable iron. Aluminum was not a material identified for Waterford 3 high-voltage insulators.

to W3F1-2016-0075 Page 26 of 42 RAI 3.6.2.2.3-1

Background:

Section 54.21(a)(3) of 10 CFR requires the 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. As described in SRP-LR, an applicant may demonstrate compliance with 10 CFR 54.21(a)(3) by referencing the GALL Report, and when evaluation of the matter in the GALL Report applies to the plant.

Section 3.6.2.2.3 of SRP-LR, Loss of Material due to Wind Induced Abrasion and Fatigue, Loss of Conductor Strength due to Corrosion, and Increased Resistance of Connections due to Oxidation or Loss of Pre-Load states that: Loss of material due to wind induced abrasion and fatigue, loss of conductor strength due to corrosion, and increased resistance of connections due to oxidation or loss of pre-load could occur in transmission conductors and connection, and in switchyard bus and connections. The GALL Report recommends further evaluation of a plant-specific AMP to ensure that this aging effect is adequately managed.

In LRA 3.6.2.2.3, the applicant references SRP-LR for further evaluation of the above aging mechanisms and effects for transmission conductors. Items from Table 3.6-1 of NUREG-1800, incorporated into LRA Table 3.6.1, line items 3.6.1-4 and 3.6.1-7 identify Transmission conductors composed of aluminum, steel. The corresponding transmission conductor items in table 3.6.2 of the LRA identify the material as aluminum.

Similarly, LRA table 3.6.1, line item 3.6.1-6, identifies the component as: Switchyard bus and connections composed of aluminum, copper, bronze, stainless steel, galvanized steel. The corresponding item in table 3.6.2 of the LRA, identifies the material as: aluminum, steel, steel alloy.

Issue:

The staff noted an apparent discrepancy between LRA table 3.6.1 and table 3.6.2 in describing the material used for transmission conductors. Table 3.6.2 of the LRA is inconsistent with table 3.6.1 in that it has omitted steel from the list of materials that constitute transmission conductors for items corresponding to 3.6.1-4 and 3.6.1-7. It is not clear whether this discrepancy is based on a plant-specific evaluation that determined a lack of such material for transmission conductors at Waterford 3 or is a result of inadvertent omission.

There is also an inconsistency between LRA table 3.6.1 and table 3.6.2 in that copper, bronze and galvanized steel have been omitted from LRA table 3.6.2 for the switchyard bus and connections line item corresponding to 3.6.1-6. It is not clear whether this discrepancy is based on a plant-specific evaluation that determined a lack of such material for switchyard connections at Waterford 3 or is a result of inadvertent omission.

Request:

1. Clarify the apparent discrepancy between LRA tables 3.6.1 and 3.6.2 regarding transmission conductor material.

2. Clarify the discrepancy between LRA tables 3.6.1 and 3.6.2 regarding switchyard bus and connections material.

Enclosure 1 to W3F1-2016-0075 Page 27 of 42 Waterford 3 Response

1. LRA Table 3.6.1 lists the materials in NUREG-1800, Table 3.6-1. Based on the WF3 electrical screening and aging management review report, transmission conductors are all aluminum conductor, steel-reinforced (ACSR) construction. The two (2) line items in LRA Table 3.6.2-1 for transmission conductors will be modified to include steel as a material.

2. LRA Table 3.6.1 lists the materials in NUREG-1800, Table 3.6-1. LRA Table 3.6.2-1 does not list material that is not used in Waterford 3 electrical component types. Based on the WF3 electrical screening and aging management review report, the switchyard bus (both large and small diameter) is aluminum tube, and connections are aluminum, steel, and stainless steel. Stainless steel is included as a material for switchyard bus and connections in LRA Table 3.6.2-1 as steel alloy. The absence of copper, bronze and galvanized steel is based on a plant-specific evaluation that determined a lack of such material for switchyard bus and connections at Waterford 3.

LRA revisions follow. Additions are shown with underline and deletions with strikethrough.

Table 3.6.2-1: Electrical and I&C Components Aging Effect Aging Component Intended Requiring Management NUREG- Table 1 Type Function Material Environment Management Programs 1801 Item Item Notes Transmission CE Aluminum, Air - outdoor None None VI.A.LP-46 3.6.1-4 C conductors steel VI.A-16 (transmission (LP-08) conductors for SBO recovery)

Transmission CE Aluminum, Air - outdoor None None VI.A.LP-47 3.6.1-7 I conductors steel VI.A-16 (transmission (LP-08) conductors for SBO recovery) to W3F1-2016-0075 Page 28 of 42 RAI 3.1.1.88-1

Background:

In the License Renewal Application (LRA) for Waterford, Unit 3, Table 3.1.1, item 3.1.1-88, addresses loss of material due to pitting and crevice corrosion for stainless steel, steel with nickel-alloy or stainless steel cladding, and nickel alloy reactor coolant pressure boundary components exposed to reactor coolant. It is indicated in LRA item 3.1.1-88 that the aging effect is managed by using the Water Chemistry Control -

Primary and Secondary Program and the One-Time Inspection Program. The One-Time Inspection Program will verify the effectiveness of the water chemistry program. In addition, LRA Table 3.1.2-4 indicates that LRA item 3.1.1-88 is used to manage loss of material due to pitting and crevice corrosion for steam generator (SG) channel heads and tubesheets.

In relation to its review of LRA item 3.1.1-88, the staff notes that U.S. Nuclear Regulatory Commission (NRC)

Information Notice (IN) 2013-20, Steam Generator Channel Head and Tubesheet Degradation (Agencywide Documents Access Management System Accession No. ML13204A143), indicates that loss of material due to boric acid corrosion could occur in the steel base material of SG channel heads and tubesheets if the SG cladding is compromised (e.g., due to cracking, manufacturing defects, maintenance, or foreign material impingement damage). Furthermore, NRC IN 2013-20 highlights the importance of performing visual inspections to ensure integrity of the SG channel head, tubesheet, and associated cladding.

The staff is currently finalizing License Renewal Interim Staff Guidance 2016-01, Changes to Aging Management Guidance for Various Steam Generator Components. This guidance highlights the importance of doing general visual inspections of the SG channel head. These visual inspections offer the opportunity not only to detect loss of material of the SG channel head and tubesheet, but also to detect gross distortion of components such as the divider plate assemblies and potential cracking/degradation of the tube-to-tubesheet welds. Current industry recommendations for performing SG channel head visual inspections are to perform such inspections each time the SG manway is opened for performing tube inspections (which, for Waterford, Unit 3, could be every 72 effective full power months or every third refueling outage, whichever results in more frequent inspections).

Issue:

The LRA does not clearly address which aging management review (AMR) items are used to manage loss of material due to boric acid corrosion for SG channel heads and tubesheets.

Request:

1. Describe the AMR items that are used to manage loss of material due to boric acid corrosion for SG channel heads and tubesheets, including aging management programs. Please discuss whether periodic visual inspections will be performed to ensure integrity of the SG channel heads and tubesheets.

2. Please discuss whether these visual inspections will also be used as part of the management of the possible degradation of the SG tube-to-tubesheet welds and divider plate assemblies (e.g., cracking associated with rust stains or gross distortion of primary side components). If so, please revise the AMR items for SG tube-to-tubesheet welds and divider plate assemblies associated with LRA item 3.1.1-25 in LRA Table 3.1.2-4, as needed, to reflect these visual inspections.

to W3F1-2016-0075 Page 29 of 42 Waterford 3 Response

1. Alloy 690 cladding is applied to the steam generator channel head and tubesheet to prevent contact with the primary coolant, which could cause loss of material due to boric acid corrosion. The assessment of aging effects that could affect the surface of the channel head and tubesheet considered aging effects applicable to the Alloy 690 cladding. Consequently, Entergy credited the Water Chemistry Control - Primary and Secondary Program with its associated One-Time Inspection Program to manage loss of material. This is consistent with the NUREG-1800 recommendations for steel with nickel alloy cladding associated with LRA Item 3.1.1-88.

A breach of steam generator channel head or tubesheet cladding is necessary to allow loss of material due to boric acid corrosion. The maximum extent of low-alloy steel wastage without visible evidence of degradation is limited by the amount of under-clad volume that can be accommodated by the cladding before it fails. Specifically, corrosion deposits would form under the cladding and force it to expand until it failed producing visible damage. Given the small amount of under-clad deposits that can be accommodated by the cladding without visible damage, structurally unacceptable (i.e., exceeding Code stress margins) loss of material is not expected without readily visible indications. Because of the Alloy 690 cladding, loss of material due to boric acid corrosion is not considered an aging effect requiring management. However, the Steam Generator Integrity Program will be modified to include periodic general visual inspections of steam generator channel heads and tubesheets exposed to treated borated water.

2. The Waterford 3 steam generator partition plates (divider plates) and tube-to-tubesheet welds are made of Alloy 690 which is resistant to primary water stress corrosion cracking. Consequently, Entergy credited the Water Chemistry Control - Primary and Secondary Program with its associated One-Time Inspection Program to manage cracking. This is consistent with the NUREG-1800 recommendations for steel with nickel alloy cladding associated with LRA Item 3.1.1-25. The further evaluation section of NUREG-1800 that is associated with LRA Item 3.1.1-25 is Section 3.1.2.2.11, which indicates that for plants with Alloy 690 steam generator tubes with Alloy 690 tubesheet cladding, the water chemistry program is sufficient, and no further action or plant-specific aging management program is necessary.

However, the Steam Generator Integrity Program will be modified to include periodic general visual inspections of steam generator channel heads and tubesheets exposed to treated borated water. In addition, the inspections will verify no visible distortion or displacement of the partition plates.

LRA Table 3.1.1, Table 3.1.2-4, Section A.1.37, and Section B.1.37 are revised to indicate that the Steam Generator Integrity Program will manage loss of material of the steam generator channel heads and tubesheet and will manage cracking of the steam generator partition plate and tube-to-tubesheet welds.

In addition to LRA changes as a result of this RAI response, changes are made to the same LRA sections as a result of RAI B.1.37-1. LRA changes as a result of RAI B.1.37-1 and RAI 3.1.1.88-1 are shown in the response to RAI B.1.37-1.

to W3F1-2016-0075 Page 30 of 42 RAI B.1.37-1

Background:

In the LRA for Waterford, Unit 3, Table 3.1.2-4, it is stated that cracking of the Steam Generator (SG) tubesheet, which is made of carbon steel clad with Alloy 690 and is exposed to treated borated water on the primary side, is managed by the Inservice Inspection Program and Water Chemistry Control - Primary and Secondary Program. LRA Table 3.1.2-4 also indicates that this AMR item is associated with LRA item 3.1.1-

45. The primary side of a SG tubesheet is typically inspected by visual inspections as part of the Steam Generator Integrity Program in conjunction with plug visual inspections and possibly through the tube inspections (e.g., the general condition of the tubesheet may be able to be assessed through cameras used to monitor probe insertion into a tube).

Issue:

It is not clear to the staff how cracking of the SG tubesheet is managed by the Inservice Inspection Program rather than by the Steam Generator Integrity Program.

Request:

1. Discuss how degradation (aging) of the SG tubesheet is managed by the Inservice Inspection Program (i.e., list which sections of American Society of Mechanical Engineers Boiler and Pressure Vessel Code,Section XI, Rules for Inservice Inspection, are used).

2. If a program other than the Inservice Inspection Program is credited to manage cracking for the SG tubesheet, please revise the AMR items for the component accordingly.

Waterford 3 Response

1. Inspection of the tubesheet primary side is not required by the Inservice Inspection Program. The reference to Inservice Inspection Program is removed from the LRA Table 3.1.2-4 line item for steam generator tubesheet.

The Waterford 3 steam generator tubesheet is clad with Alloy 690 which is resistant to primary water stress corrosion cracking. Consequently, Entergy will credit the Water Chemistry Control - Primary and Secondary Program to manage cracking. This is consistent with the NUREG-1800 recommendations for steel with nickel alloy cladding associated with LRA Item 3.1.1-25. The further evaluation section of NUREG-1800 that is associated with LRA Item 3.1.1-25 is Section 3.1.2.2.11, which indicates that for plants with Alloy 690 steam generator tubes with Alloy 690 tubesheet cladding, the water chemistry program is sufficient, and no further action or plant-specific aging management program is necessary.

Nevertheless, the Steam Generator Integrity Program will be modified to include periodic general visual inspections of steam generator channel heads and tubesheets exposed to treated borated water.

2. The LRA is revised to indicate that the Steam Generator Integrity Program will include a general visual inspection of the steam generator tubesheet cladding each time the steam generator manway is opened for performing tube inspections.

In addition to LRA changes as a result of this RAI response, changes are made to the same LRA sections as a result of RAI 3.1.1.88-1. LRA changes as a result of RAI B.1.37-1 and RAI 3.1.1.88-1 are shown below. Additions are underlined and deletions are lined through.

to W3F1-2016-0075 Page 31 of 42 Table 3.1.1 Summary of Aging Management Programs for the Reactor Coolant System Evaluated in Chapter IV of NUREG-1801 Table 3.1.1: Reactor Coolant System Item Aging Effect/ Aging Management Further Evaluation Number Component Mechanism Programs Recommended Discussion 3.1.1-25 Steel (with nickel-alloy Cracking due to Chapter XI.M2, Yes, plant-specific Cracking of nickel alloy (Alloy cladding) or nickel alloy primary water stress Water Chemistry 690) steam generator tube to steam generator primary corrosion cracking tubesheet welds and the partition side components: plate is managed by the Steam divider plate and tube- Generator Integrity and Water to-tube sheet welds Chemistry Control - Primary and exposed to reactor Secondary Programs. Cracking coolant of the nickel alloy (Alloy 690) steam generator primary side divider plate exposed to reactor coolant is managed by the Water Chemistry Control - Primary and Secondary Program.

See Section 3.1.2.2.11, Items 1 and 2 to W3F1-2016-0075 Page 32 of 42 Table 3.1.2-4 Steam Generators Summary of Aging Management Evaluation Table 3.1.2-4: Steam Generators Aging Effect Component Intended Requiring Aging Management NUREG-1801 Table 1 Type Function Material Environment Management Program Item Item Notes Tubesheet Pressure Carbon steel Treated borated Cracking Inservice Inspection IV.D1.RP-385 3.1.1-25 E C, 103 boundary clad with nickel water (int) Water Chemistry IV.D1.RP-36 3.1.1-45 alloy (Alloy 690) Control - Primary and Secondary Tube to Pressure Nickel alloy Treated borated Cracking Steam Generator IV.D1.RP-385 3.1.1-25 A tubesheet weld boundary (Alloy 690) water Integrity Water Chemistry Control - Primary and Secondary A.4 LICENSE RENEWAL COMMITMENT LIST Implementation Source No. Program or Activity Commitment Schedule (Letter Number) 33 Steam Generator Enhance the Steam Generator Integrity Program as Prior to June 18, W3F1-2016-0075 Integrity described in LRA Section B.1.37. 2024 to W3F1-2016-0075 Page 33 of 42 A.1.37 Steam Generator Integrity Program The Steam Generator Integrity Program manages aging effects for the steam generator tubes, plugs, sleeves, and secondary side components contained within the steam generator in accordance with the plant technical specifications and commitments to NEI 97-06. Preventive and mitigative measures include foreign material exclusion programs and other primary and secondary side maintenance activities, such as sludge lancing and inspecting any installed plugs and replacing them when needed with updated materials as needed. The program has acceptance criteria for when a tube should be plugged based on wall thickness measurements.

Steam generator water chemistry is monitored and maintained in accordance with the Water Chemistry Control - Primary and Secondary Program. The thermally treated Alloy 690 tubes are monitored for wear based on industry experience using inspection techniques capable of detecting the aging effect. The general conditions of components (e.g., plugs when installed, sleeves, tubesheet primary side, channel head surfaces exposed to reactor coolant, partition plate, and other secondary side components) are monitored visually. Inspections of primary side components will verify no rust stains, discoloration, or distortion of the cladding that could indicate loss of material due to boric acid corrosion of base metals resulting from a breach of the cladding. In the event degradation is noted, the corrective action program drives a more detailed inspection. The inspections are performed by qualified personnel using qualified techniques in accordance with approved station procedures. In addition primary-to-secondary leak rates are monitored as a potential indicator of steam generator tube integrity. Condition monitoring assessments are performed and documented in accordance with site-approved procedures to confirm that adequate tube integrity has been maintained since the previous inspection. Operational assessments are performed to ensure the tube integrity will be maintained until the next scheduled inspection. The acceptance criteria are in accordance with technical specifications B.1.37 Steam Generator Integrity Program Description The Steam Generator Integrity Program manages aging effects for the steam generator tubes, plugs, sleeves, and secondary side components contained within the steam generator in accordance with the plant technical specifications and commitments to NEI 97-06. Preventive and mitigative measures include foreign material exclusion programs and other primary and secondary side maintenance activities, such as sludge lancing and inspecting any installed plugs and replacing them with updated materials as needed.

The program has acceptance criteria for when a tube should be plugged based on wall thickness measurements.

Steam generator water chemistry is monitored and maintained in accordance with the Water Chemistry Control - Primary and Secondary Program. The thermally treated Alloy 690 tubes are monitored for wear based on industry experience using inspection techniques capable of detecting the aging effect. The general conditions of components (e.g., plugs when installed, sleeves, tubesheet primary side, channel head surfaces exposed to reactor coolant, partition plate, and other secondary side components) are monitored visually. Inspections of primary side components will verify no rust stains, discoloration, or distortion of the cladding that could indicate loss of material due to boric acid corrosion of base metals resulting from a breach of the cladding. In the event degradation is noted, the corrective action program drives a more detailed inspection. The inspections are performed by qualified personnel using qualified techniques in accordance with approved station procedures. In addition, primary-to-secondary leak rates are monitored as a potential indicator of steam generator tube integrity. Condition monitoring assessments are performed and documented in accordance with site-approved procedures to confirm that to W3F1-2016-0075 Page 34 of 42 adequate tube integrity has been maintained since the previous inspection. Operational assessments are performed to ensure the tube integrity will be maintained until the next scheduled inspection. The acceptance criteria are in accordance with technical specifications.

NUREG-1801 Consistency The Steam Generator Integrity Program, with enhancements, will be is consistent with the program described in NUREG-1801,Section XI.M19, Steam Generator.

Enhancements None The following enhancements will be implemented prior to the period of extended operation.

Element Affected Enhancement

4. Detection of Aging Effects Revise the Steam Generator Integrity Program to include general visual inspection of the partition plate, channel head, and tubesheet (primary side).

Table B-3 WF3 Program Consistency with NUREG-1801 NUREG-1801 Comparison Program has Plant- Program has Exceptions to Program Name Specific Enhancements NUREG-1801 Steam Generator Integrity [B.1.37] X to W3F1-2016-0075 Page 35 of 42 RAI B.1.10-4

Background

1. GALL Report AMP XI.M36, External Surfaces Monitoring of Mechanical Components, recommends inspections for leakage to identify cracking of stainless steel external surfaces exposed to air environments containing halides.

LRA Section B.1.10 states that inspection parameters include leakage for detection of cracks on the external surfaces of stainless steel components exposed to an air environment containing halides. LRA Tables 3.3.2-4, 3.3.2-11, 3.3.2-12, 3.3.2-14, 3.3.2-15-6, and 3.4.2-4 contain AMR items for stainless steel components exposed to an outdoor air or condensation external environment and a gaseous, condensation, or indoor air internal environment. Cracking is managed for these components with the External Surfaces Monitoring program.

2. LRA Tables 3.3.2-3 and 3.3.2-13 contain AMR items for aluminum components exposed to an outdoor air or condensation environment that will be managed for cracking using the External Surfaces Monitoring program.

Issue

1. For stainless steel components that have a gaseous, condensation, or indoor air internal environment, it is not clear to the staff how inspections of external surfaces will effectively use leakage as an indicator of cracking.

2. Methods for detecting cracking in aluminum components are not specified in the External Surfaces Monitoring program.

Request

1. State the parameters monitored and the inspection methods that will be used to determine whether cracking is present in the stainless steel components in LRA Tables 3.3.2-4, 3.3.2-11, 3.3.2-12, 3.3.2-14, 3.3.2-15-6, and 3.4.2-4 with a gaseous, condensation, or indoor air internal environment.

2. State the inspection parameters monitored and the inspection methods that will be used to determine whether cracking is present in the aluminum components in LRA Tables 3.3.2-3 and 3.3.2-13.

to W3F1-2016-0075 Page 36 of 42 Waterford 3 Response

1. For stainless steel components:

The External Surfaces Monitoring Program provides for inspections during system walkdowns to identify evidence of corrosion and leakage. Leakage of gases resulting from cracking can be identified not only by visual inspection, but by audible sounds created by leaking gases.

Table 3.3.2-4 Compressed Air The External Surfaces Monitoring Program manages cracking in stainless steel components. The program includes system walkdowns during which, leakage through a crack can be detected by audible sound from the escaping compressed air.

Table 3.3.2-11 Nitrogen The External Surfaces Monitoring Program manages cracking in stainless steel tubing in the nitrogen system. The program includes system walkdowns during which, leakage through a crack can be detected by audible sound from the escaping nitrogen.

Table 3.3.2-12 Miscellaneous HVAC The stainless steel component with gaseous internal environment is the plant stack monitoring instrument tubing. A search of WF3 operating experience was performed to determine if cracking of stainless steel tubing had been documented in stainless steel components exposed to an external environment of air-outdoor. No items were identified. In addition, stainless steel tubing exposed to outdoor air is widely used in pressurized systems that are subject to aging management review at WF3. Identification of cracking caused by exposure of that tubing to outdoor air would be an indicator that corrective actions should be taken with respect to the stainless steel tubing in the miscellaneous HVAC system. Based on the operating experience review, cracking is not an aging effect requiring management for the stainless steel tubing with indoor air internal environment in the miscellaneous HVAC system. LRA Table 3.3.2-12 is revised accordingly.

Table 3.3.2-14 Plant Drains The stainless steel components that credit the External Surfaces Monitoring Program for managing cracking are exposed to an internal environment of waste water; not a gaseous environment. .

Table 3.3.2-15-6 Boron Management No stainless steel components were identified with a gaseous internal environment. The identified internal environments are treated borated water and waste water.

Table 3.4.2-4 Main Steam Stainless steel components in the main steam system are exposed to an internal environment of steam. Inspections during system walkdowns can detect leakage by indications of steam plumes and water vapor in the surrounding areas. Steam leaks can also be detected by audible sounds from the escaping steam.

to W3F1-2016-0075 Page 37 of 42

2. For aluminum components Table 3.3.2-3 Component Cooling/Aux Component Cooling Water System The aluminum components in the component cooling/aux component cooling water systems are the heat exchanger fins on tubes in the dry cooling towers. Heat exchanger fins are not pressure boundary components, so inspection for leakage to indicate cracking is not applicable.

Table 3.3.2-13 Auxiliary Diesel Generator The aluminum component in the auxiliary diesel generator system is the flame arrestor on the fuel oil tank vent line. The flame arrestor consists of a cast iron base, cover and posts, plus aluminum weather shields and plate stacks. Further review of this component has determined that it does not perform the license renewal intended function of pressure boundary. Table 2.3.3-13 and Table 3.3.2-13 are revised to remove the aluminum flame arrestor.

LRA changes follow. Additions are underlined and deletions are lined through.

Table 2.3.3-13 Auxiliary Diesel Generator System Components Subject to Aging Management Review Component Type Intended Function Bolting Pressure boundary Expansion joint Pressure boundary Flame arrestor Pressure boundary Piping Pressure boundary Silencer Pressure boundary Tank Pressure boundary Tubing Pressure boundary Valve body Pressure boundary 3.3.2.2 Further Evaluation of Aging Management as Recommended by NUREG-1800 3.3.2.2.3 Cracking due to Stress Corrosion Cracking Cracking due to stress corrosion cracking could occur for stainless steel piping, piping components, piping elements and tanks exposed to outdoor air, including air which has recently been introduced into buildings, such as near intake vents. WF3 is located near other industrial facilities, including chemical manufacturers. Chloride contamination of components exposed to outdoor air may occur. Consistent with NUREG-1801, cracking of stainless steel components exposed to outdoor air, including indoor components accessible to outdoor air, is identified as an aging effect requiring management and is managed by the External Surfaces Monitoring Program.

to W3F1-2016-0075 Page 38 of 42 In Table 3.3.2-12, Miscellaneous HVAC, stainless steel tubing, which serves the plant stack monitoring instrumentation, is exposed externally to air-outdoor and has an internal environment of air-indoor. Waterford 3 operating experience was reviewed to determine if cracking had been documented in stainless steel components exposed to an external environment of air-outdoor. No occurrences were identified. Therefore, cracking of the stainless steel tubing in the stack monitoring system is not expected. Based on the operating experience review, cracking due to stress corrosion cracking is not an aging effect requiring management for the subject tubing.

3.3.2.2.5 Loss of Material due to Pitting and Crevice Corrosion Loss of material due to pitting and crevice corrosion could occur for stainless steel piping, piping components, piping elements, and tanks exposed to outdoor air, including air which has recently been introduced into buildings, such as near intake vents. WF3 is located near other industrial facilities, including chemical manufacturers. Chloride contamination of components exposed to outdoor air may occur. Consistent with NUREG-1801, loss of material for stainless steel components exposed to outdoor air, including indoor components accessible to outdoor air, is identified as an aging effect requiring management and is managed by the External Surfaces Monitoring Program.

In Table 3.3.2-12, Miscellaneous HVAC, stainless steel tubing, which serves the plant stack monitoring instrumentation, is exposed externally to air-outdoor and has an internal environment of air-indoor. Waterford 3 operating experience was reviewed to determine if loss of material had been documented for stainless steel components exposed to an external environment of air-outdoor. No occurrences were identified. Therefore, loss of material of the stainless steel tubing in the stack monitoring system is not expected. Based on the operating experience review, loss of material due to pitting and crevice corrosion is not an aging effect requiring management for the subject tubing.

to W3F1-2016-0075 Page 39 of 42 Table 3.3.1 Summary of Aging Management Programs for the Auxiliary Systems Evaluated in Chapter VII of NUREG-1801 Table 3.3.1: Auxiliary Systems Item Aging Effect/ Aging Management Further Evaluation Number Component Mechanism Programs Recommended Discussion 3.3.1-4 Stainless steel piping, Cracking due to Chapter XI.M36, "External Yes, environmental Consistent with NUREG-1801.

piping components, stress corrosion Surfaces Monitoring of conditions need to Cracking in stainless steel and piping elements; cracking Mechanical Components" be evaluated components exposed to tanks exposed to air outdoor air is managed by the

- outdoor External Surfaces Monitoring Program (with the exception of the plant stack monitoring instrument tubing).

See Section 3.3.2.2.3.

3.3.1-5 Steel (with stainless Loss of material A plant-specific aging Yes, verify that The WF3 charging pump steel or nickel-alloy due to cladding management program is to plant- specific casings are solid stainless cladding) pump breach be evaluated. Reference program addresses steel.

casings exposed to NRC Information Notice 94- clad cracking treated borated water 63, Boric Acid Corrosion of See Section 3.3.2.2.4.

Charging Pump Casings Caused by Cladding Cracks."

3.3.1-6 Stainless steel piping, Loss of material Chapter XI.M36, "External Yes, environmental Consistent with NUREG-1801.

piping components, due to pitting and Surfaces Monitoring of conditions need to Loss of material in stainless and piping elements; crevice corrosion Mechanical Components" be evaluated steel components exposed to tanks exposed to air outdoor air is managed by the

- outdoor External Surfaces Monitoring Program (with the exception of the plant stack monitoring instrument tubing).

See Section 3.3.2.2.5.

to W3F1-2016-0075 Page 40 of 42 Table 3.3.2-12 Miscellaneous HVAC Systems Summary of Aging Management Evaluation Table 3.3.2-12: Miscellaneous HVAC Systems Aging Effect Aging Component Intended Requiring Management NUREG-1801 Table 1 Type Function Material Environment Management Program Item Item Notes Tubing Pressure Stainless steel Air - indoor None None VII.J.AP-123 3.3.1-120 A boundary (ext)

Tubing Pressure Stainless steel Air - indoor None None VII.J.AP-123 3.3.1-120 A boundary (int)

Tubing Pressure Stainless steel Air - outdoor None None VII.F2.AP-209 3.3.1-4 I boundary (ext)

Cracking External VII.F2.AP-221 3.3.1-6 A Surfaces Monitoring Tubing Pressure Stainless steel Air - outdoor Loss of material External VII.F2.AP-221 3.3.1-6 A boundary (ext) Surfaces Monitoring to W3F1-2016-0075 Page 41 of 42 Table 3.3.2-13 Auxiliary Diesel Generator System Summary of Aging Management Evaluation Table 3.3.2-13: Auxiliary Diesel Generator System Aging Effect Aging Component Intended Requiring Management NUREG-1801 Table 1 Type Function Material Environment Management Program Item Item Notes Bolting Pressure Carbon steel Air - indoor Loss of material Bolting Integrity VII.I.AP-125 3.3.1-12 B boundary (ext)

Bolting Pressure Carbon steel Air - indoor Loss of preload Bolting Integrity VII.I.AP-124 3.3.1-15 B boundary (ext)

Bolting Pressure Stainless steel Air - indoor Loss of preload Bolting Integrity VII.I.AP-124 3.3.1-15 B boundary (ext)

Expansion joint Pressure Stainless steel Air - indoor None None VII.J.AP-123 3.3.1-120 A boundary (ext)

Flame arrestor Pressure Aluminum Air - outdoor Cracking External -- -- H boundary (ext) Surfaces Monitoring Flame arrestor Pressure Aluminum Air - outdoor Loss of material External VII.I.AP-256 3.3.1-81 A boundary (ext) Surfaces Monitoring Flame arrestor Pressure Aluminum Air - outdoor Cracking External -- -- H boundary (int) Surfaces Monitoring Flame arrestor Pressure Gray cast iron Air - outdoor Loss of material External VII.H1.A-24 3.3.1-80 A boundary (ext) Surfaces Monitoring Flame arrestor Pressure Gray cast iron Air - outdoor Loss of material External -- -- G, 305 boundary (int) Surfaces Monitoring to W3F1-2016-0075 Page 42 of 42 RAI 4.7.4-1

Background:

LRA Section 4.7.4 provides the applicant TLAA for the aging evaluation of reactor vessel internals (RVI),

other than those associated with applicants metal fatigue TLAA for these components. The applicant identifies that the aging evaluations of irradiation-assisted stress corrosion cracking and loss of fracture toughness due to thermal aging and neutron irradiation embrittlement in its 2003 extended power uprate (EPU) license amendment request are analyses that conform to the definition of a TLAA in 10 CFR 54.3(a). The applicant stated that the implementation of LRA AMP B.1.33, Reactor Vessel Internals Program, will ensure that these TLAAs are acceptable in accordance with 10 CFR 54.21(c)(1))(iii).

The license amendment request for the EPU was submitted on November 3, 2003, and approved in an NRC-issued safety evaluation (SE) dated April 15, 2005 (ML051030068). Section 2.1.4 of the SE identifies that the projected neutron fluences for RVI components in the vicinity of the reactor core will range from 3.0 - 5.0 X 1022 n/cm2 (E > 0.1 MeV) through 40 years of licensed operations.

Issue:

EPRI Report MRP-191 estimates that RVI components in the core shroud would generally have neutron fluences ranging from 1.0 - 5.0 X 1022 n/cm2 through 60 years of licensed operations. The staff needs additional demonstration that the neutron fluence values for these types of RVI components through 60 years of licensed operation will not exceed the fluence estimates for the components in Table 4-7 of the MRP-191 report. Otherwise, the staff will need further assessment of the inspection bases for core shroud assembly components if the 60-year projected fluences for these components will exceed those specified for the components in MRP-191.

Request:

Justify (with a technical explanation) why the projected neutron fluences for RVI core shroud components through 60 years of operations are considered bounded by the fluence estimates for these components in Table 4-7 of the MRP-191 report. Otherwise, clarify what the impact will be on the FMECA assessment for these components and the inspection plan for RVI components if the 60-year neutron fluence value for any RVI core shroud component will exceed the neutron fluence estimate for the component in Table 4-7 of the MRP-191 report.

Waterford 3 Response Response to RAI 4.7.4-1 to accompany Set 5 RAI 4.2.3-1 response expected to be submitted in early February 2017 as discussed in email from P. Clark (NRC) to A. Harris (Entergy) dated 11/21/2016.

Enclosure 2 to W3F1-2016-0075 Commitment 33 Waterford 3 License Renewal Application to W3F1-2016-0075 Page 1 of 1 EMPTY A.4 LICENSE RENEWAL COMMITMENT LIST (ADDITION)

Implementation Source No. Program or Activity Commitment Schedule (Letter Number) 33 Steam Generator Enhance the Steam Generator Integrity Program as Prior to June 18, W3F1-2016-0075 Integrity described in LRA Section B.1.37. 2024