Text

Response to License Renewal Application NRC Request for Additional Information - Set 7
	ML18087A164
Person / Time
Site:	River Bend
Issue date:	02/07/2018
From:	Maguire W; Entergy Operations
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
Shared Package
ML18087A517	List: RBG-47818, Response to License Renewal Application NRC Request for Additional Information - Set 7;
References
	CAC MF9757, RBG-47818
	Download: ML18087A164 (67)
	v • d • e

{{#Wiki_filter:* Entergx .~. Entergy Operations, Inc. River Bend Station 5485 U S Highway 61 N St FrancIsville LA 70775 Tel 225*381*4374 William F. Maguire Site Vice President River Bend Station RBG-47818 February 7, 2018 Attn : Document Control Desk U.S. Nuclear Regulatory Commission 11555 Rockville Pike Rockville , MD 20852-2738

SUBJECT:

Response to License Renewal Application NRC Request for Additional Information - Set 7 River Bend Station , Unit 1 Docket No. 50-458 License No. NPF-47

References:

1) Entergy Letter: License Renewal Application (RBG-47735 dated May 25, 2017

2) NRC email : River Bend Station, Unit 1, Request for Additional Information ,

Set 7 - RBS License Renewal Application - dated January 9, 2018 (ADAMS Accession No. ML18009A909)

3) Entergy Letter: Request for Due Date Extension for License Renewal Application NRC Request for Additional Information - Set 7 (B.11 .1.2a) -

(RBG-47821 dated January 18, 2018)

Dear Sir or Madam :

In Reference 1, Entergy Operations, Inc (Entergy) submitted an application for renewal of the operating license for River Bend Station (RBS) for an additional 20 years beyond the current expiration date. In an email dated January 9, 2018 , (Reference 2) the NRC staff made a request for additional information (RAI) , needed to complete the license renewal application (LRA) review. Enclosure 1 provides the responses to the Set 7 RAls . Enclosure 2 identifies a commitment that will be included in section A4 of the LRA. Enclosure 3 contains information that is considered to be non-proprietary. Enclosure 4 contains information that is considered proprietary; therefore, Enclosure 4 is requested to be withheld from disclosure to the public under 10 CFR 2.390. An affidavit from GE-Hitachi Nuclear Energy Americas LLC supporting withholding under 10 CFR 2.390 is prQvided in Enclosure 4. Due to the expanded research needed to respond to RAI B.11 .1.2a a request for a due date extension from 30 to 60 days was provided in Reference 3. The response to this RAI will be provided by March 12, 2018. If you require additional information , please contact Mr. Tim Schenk at (225)-381-4177 or tschenk@entergy.com .

RBG-47818 Page 2 of 3 In accordance with 10 CFR 50.91(b)(1) , Entergy is notifying the State of Louisiana and the State of Texas by transmitting a copy of this letter to the designated State Official. I declare under penalty of perjury that the foregoing is true and correct. Executed on February 7, 2018 . Sincerely, WFM/RMC/alc Enclosure 1: Set 7 RAI Responses - River Bend Station Enclosure 2: Set 7 Commitment - River Bend Station Enclosure 3: Set 7 RAI4.7.1-1 Non-proprietary Information - River Bend Station Enclosure 4: Set 7 RAI4.7.1-1 Proprietary Information - River Bend Station

RBG-47818 Page 3 of 3 cc: (with Enclosure) U. S. Nuclear Regulatory Commission Attn : Emmanuel Sayoc 11555 Rockville Pike Rockville , MD 20852 cc: (w/o Enclosure) U. S. Nuclear Regulatory Commission Attn : Lisa Regner 11555 Rockville Pike Rockville , MD 20852 U.S. Nuclear Regulatory Commission Region IV 1600 East Lamar Blvd. Arlington , TX 76011-4511 NRC Resident Inspector PO Box 1050 St. Francisville, LA 70775 Central Records Clerk Public Utility Commission of Texas 1701 N. Congress Ave . Austin , TX 78711-3326 Department of Environmental Quality Office of Environmental Compliance Radiological Emergency Planning and Response Section Ji Young Wiley P.O. Box 4312 Baton Rouge , LA 70821-4312

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RBG-47818 Enclosure 1 Responses to Request for Additional Information Set 7

RBG-47818 Page 2 of 44 REQUEST FOR ADDITIONAL INFORMATION LICENSE RENEWAL APPLICATION RIVER BEND STATION, UNIT 1 - SET 7 DOCKET NO.: 50-458 CAC NO.: MF9757 Office of Nuclear Reactor Regulation Division of Materials and License Renewal Question RAI 3.3.1-1 (TRP 28 Fire Water System)

Background

LRA Table 3.3.1, items 3.3.1-64, 3.3.1-66, 3.3.1-130, and 3.3.1-131 , which cite generic notes Band 0 , do not cite flow blockage due to fouling as an aging effect requiring management in the Discussion column of Table 3.3.1, nor in LRA Table 3.3.2 7. The GALL Report AMP XI,M27 , "Fire Water System ," as modified by LR ISG 2012 02, as well as the USAR supplement for the program , cite flow blockage due to fouling as an applicable aging effect requiring management. Issue Even though the Fire Water System program , as well as the USAR supplement for the program include provisions to manage flow blockage due to fouling , LRA Tables 3.3.1 and 3.3.2 7 do not cite flow blockage due to fouling as an aging effect requiring management. Request State whether flow blockage due to fouling will be managed for components citing items 3.3.1 64, 3.3.1-66, 3.3.1-130, and 3.3.1-131 , and generic notes Band D.

1. If flow blockage due to fouling will not be managed , state the basis for not managing this aging effect.

2. If flow blockage due to fouling will be managed , what changes will be incorporated into LRA Tables 3.3.1 and 3.3.2 7 necessary to address flow blockage due to fouling?

Response

The Fire Water System Program described in Sections A.1 .20 and B.1.20 of the River Bend license renewal application (LRA) manages flow blockage due to fouling for components citing Items 3.3.1-64, 3.3.1-66, 3.3.1-130, and 3.3.1-131 . For clarification , flow blockage due to fouling is being added to LRA Table 3.3.1, Items 3.3.1-64, 3.3.1-66, 3.3.1-130, and 3.3.1-131 and to the appropriate line items in LRA Table 3.3.2-7. The changes to LRA Tables 3.3.1 and 3.3.2-7 and Section 3.3.2.1.7 follow with additions underlined and deletions lined through . .

RBG-47818 Enclosure 1 Page 3 of 44 Table 3.3.1: Auxiliary Systems Further Item Aging Effectl Aging Management Evaluation Number Component Mechanism Programs Recommended Discussion 3.3.1-64 Steel , copper alloy Loss of material due Chapter XI.M27 , "Fire Water No Consistent with NUREG-1801 . Loss of piping , piping to general , pitting , System" material and flow blockage for steel components, and crevice, and and copper alloy fire protection system piping elements microbiolog ically components exposed to raw water is exposed to raw influenced managed by the Fire Water System water corrosion ; fouling Program . that leads to corrosion ; flow blockage due to fouling 3.3.1-66 Stainless steel Loss of material due Chapter XI.M27 , "Fire Water No Consistent with NUREG-1801 . Loss of piping , piping to pitting and System" material and flow blockage for components , and crevice corrosion; stainless steel fire protection system piping elements fouling that leads to components exposed to raw water is exposed to raw corrosion ; flow managed by the Fire Water System water blockage due to Program. fouling

RBG-47818 Enclosure 1 Page 4 of 44 Table 3.3.1: Auxiliary Systems Further Item Aging Effectl Aging Management Evaluation Number Component Mechanism Programs Recommended Discussion 3.3.1-130 Metallic sprinklers Loss of material due Chapter XI.M27, "Fire Water No Consistent with NUREG-1801 . Loss of exposed to air-indoor to general (where System" material and flow blockage aA9 fel:JliA§ controlled, air-indoor applicable) , pitting , ef for sprinklers internally exposed to uncontrolled , air- crevice, and raw water is managed by the Fire outdoor, moist air, microbiologically- Water System Program . condensation , raw influenced water, treated water corrosion , fouling that leads to corrosion ; flow blockage due to fouling 3.3.1-131 Steel , stainless steel, Loss of material due Chapter XI.M27, "Fire Water No Consistent with NUREG-1801 for fire copper alloy, or to general (steel, System" water system piping . Loss of material aluminum fire water and copper alloy and flow blockage for steel fire water system piping, piping only) , pitting , system piping internally exposed to components and crevice, and condensation is managed by the Fire piping elements microbiologically- Water System Program . Loss of exposed to air-indoor influenced material for steel halon system piping uncontrolled corrosion, fouling internally exposed to indoor air is (internal), air-outdoor that leads to managed by the Fire Protection (internal), or corrosion; flow Program . Loss of material for copper condensation blockage due to alloy flame arrestors internally exposed (internal) fouling to outdoor air is managed by the Internal Surfaces in Miscellaneous Piping and Ducting Components Program .

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RBG-47818 Page 5 of 44 Table 3.3.2-7 Fire Protection - Water System Summary of Aging Management Evaluation

Fire Protection - Water System Aging Effect Aging Component Intended Requiring Management NUREG-1801 Table 1 Type Function Material Environment Management Program Item Item Notes Fire hydrant Pressure Gray cast iron Raw water (int) Loss of material Fire Water VII .G.A-33 3.3.1-64 B boundary and flow blockage System Fire hydrant Pressure Gray cast iron Raw water (int) Loss of material Selective VII .G.A-51 3.3.1-72 A boundary Leaching Fire hydrant Pressure Gray cast iron Soil (ext) Loss of material Buried and VII .G.AP-198 3.3.1-106 A boundary Underground Piping and Tanks Inspection Fire hydrant Pressure Gray cast iron Soil (ext) Loss of material Selective VII.G.A-02 3.3.1-72 A boundary Leaching Flame arrestor Pressu re Copper alloy Air - outdoor Loss of material External Surfaces VII.I.AP-159 3.3.1-81 A boundary > 15% Zn or> (ext) Monitoring 8%AI Flame arrestor Pressure Copper alloy Air - outdoor Loss of material Internal Surfaces VII.G.A-404 3.3.1-131 E boundary > 15% Zn or> (int) in Miscellaneous 8%AI Piping and Ducting Components Flex hose Pressure Sta in less steel Air - indoor None None VII .J.AP-123 3.3.1-120 A boundary (ext)

RBG-47818 Page 6 of 44

Fire Protection - Water System Aging Effect Aging Component Intended Requiring Management NUREG-1801 Table 1 Type Function Material Environment Management Program Item Item Notes Flex hose Pressure Stainless steel Fuel oil (int) Loss of material Diesel Fuel VILG .AP-136 3.3.1-71 A, 303 boundary Monitoring Flow element Pressure Stainless steel Air - indoor None None VILJ .AP-123 3.3.1-120 A boundary (ext)

Flow contro l Flow element Pressure Stainless steel Raw water Loss of material Fire Water VILG .A-55 3.3.1-66 B boundary (ext) and flow blockage System Flow control Heat Pressure Copper alloy Air - indoor None None VILJ.AP-144 3.3.1-114 C exchanger boundary (ext) (channel head) Heat Pressure Copper al loy Treated water Loss of material Water Chem istry VILC2 .AP-199 3.3.1-46 C exchanger boundary (int) Control - Closed (channel head) Treated Water Systems Heat Pressure Carbon steel Air - indoor Loss of material External Surfaces VILG .AP-41 3.3.1-80 A exchanger boundary (ext) Monitoring (shell ) Heat Pressure Carbon steel Raw water (int) Loss of material Fire Water VILG .A-33 3.3.1 -64 D exchanger boundary and flow blockage System (shell) Heat Pressure Copper alloy Raw water Loss of material Fire Water VILG .AP-197 3.3.1-64 D exchanger boundary (ext) and flow blockage System (tubes)

RBG-47818 Page 7 of 44

Fire Protection - Water System Aging Effect Aging Component Intended Requiring Management NUREG-1801 Table 1 Type Function Material Environment Management Program Item Item Notes Heat Heat transfer Copper alloy Raw water Reduction of heat Internal Surfaces VII.C1 .A-72 3.3.1-42 E exchanger (ext) transfer in Miscellaneous (tubes) Piping and Ducting Components Heat Pressure Copper alloy Treated water Loss of material Water Chemistry VII.C2 .AP-199 3.3.1-46 C exchanger boundary (int) Control - Closed (tubes) Treated Water Systems Heat Heat transfer Copper alloy Treated water Reduction of heat Water Chemistry VII.C2 .AP-205 3.3.1-50 C exchanger (int) transfer Control - Closed (tubes) Treated Water Systems I I

I Heater housing Pressure Aluminum Air - indoor None None VII.J.AP-135 3.3.1-113 C boundary (ext) Heater housing Pressure Aluminum Treated water Cracking Water Chemistry -- -- H boundary (int) Control - Closed Treated Water Systems Heater housing Pressure Aluminum Treated water Loss of material Water Chemistry VII .C2.AP-254 3.3.1-48 C boundary (int) Control - Closed Treated Water Systems Insulated Pressure Gray cast iron Air - outdoor Loss of material External Surfaces VII.G .A-405 3.3.1-132 A piping boundary (ext) Monitoring components

RBG-47818 Page 8 of 44

Fire Protection - Water System Aging Effect Aging Component Intended Requiring Management NUREG-1801 Table 1 Type Function Material Environment Management Program Item Item Notes Insulated Pressure Carbon steel Air - outdoor Loss of material External Surfaces VII.G .A-405 3.3.1-132 A piping boundary (ext) Monitoring components Piping Pressure Carbon steel Air- indoor Loss of material External Surfaces VI I. I.A-77 3.3.1-78 A boundary (ext) Monitoring Piping Pressure Carbon steel Air- indoor Loss of material Fire Water VII.G .A-404 3.3.1-131 B boundary (int) and flow blockage System Piping Pressure Carbon steel Air - outdoor Loss of material External Surfaces VII.I.A-78 3.3.1-78 A boundary (ext) Monitoring Piping Pressu re Carbon steel Air - outdoor Loss of material Fire Water VII .G .A-404 3.3.1-131 B boundary (int) and flow blockage System Piping Pressure Carbon steel Condensation Loss of material Fire Water VII.G .A-404 3.3.1-131 B boundary (int) and flow blockage System Piping Pressure Carbon steel Exhaust gas Cracking - fatigue TLAA- metal V.D2.E-10 3.2.1-1 C, 308 boundary (int) fatigue i

I Piping Pressure Carbon steel Exhaust gas Loss of material Internal Surfaces VII.H2.AP-104 3.3.1-88 C I boundary (int) in Miscellaneous Piping and Ducting Components Piping Pressure Carbon steel Fuel oil (int) Loss of material Diesel Fuel VII.G .AP-234 3.3.1-68 A, 303 boundary Monitoring

RBG-47818 Page 9 of 44

Fire Protection - Water System Aging Effect Aging Component Intended Requiring Management NUREG-1801 Table 1 Type Function Material Environment Management Program Item Item Notes Piping Pressure Carbon steel Raw water Loss of materi al Fire Water VII.G .A-33 3.3.1-64 B boundary (ext) System Piping Pressure Carbon steel Raw water (int) Loss of material Fire Water VII.G .A-33 3.3.1-64 B boundary and flow blockage System Piping Pressure Carbon steel Soi l (ext) Loss of material Buried and VII.G .AP-198 3.3.1-106 A boundary Underground Piping and Tanks Inspection I

Piping Pressure Carbon steel Raw water (int) Loss of coating Coati ng Integrity VII.G .A-416 3.3.1-138 A boundary with interna l integrity coating Piping Pressure Gray cast iron Raw water (int) Loss of material Coating Integ rity VII.G .A-415 3.3.1 -140 A boundary with interna l coating Piping Pressure Carbon steel Raw water (int) Loss of material Coating Integrity VII.G.A-414 3.3.1-139 E boundary with internal coating Piping Pressure Gray cast iro n Raw water (int) Loss of material Fire Water VII.G .A-33 3.3.1-64 B boundary and flow blockage System Piping Pressure Gray cast iron Raw water (int) Loss of material Selective VII.G .A-51 3.3.1-72 A boundary Leaching

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RBG-47818 - Page 10 of 44

Fire Protection - Water System Aging Effect Aging I Component Intended Requiring Management NUREG-1801 Table 1 Type Function Material Environment Management Program Item Item Notes Piping Pressure Gray cast iron Soil (ext) Loss of material Buried and VI I, G.AP-198 3.3.1-106 A boundary Underground Piping and Tanks Inspection Piping Pressure Gray cast iron Soil (ext) Loss of material Selective VII,G .A-02 3.3.1-72 A boundary Leaching Pump casing Pressure Carbon steel Air - outdoor Loss of material External Surfaces VII .I.A-78 3.3.1-78 A boundary (ext) Mon itoring Pump cas ing Pressure Carbon stee l Raw water (int) Loss of material Fire Water VII,G.A-33 3.3.1-64 B boundary and flow blockage System Pump casing Pressure Gray cast iron Air - indoor Loss of material External Surfaces VI I. I,A-77 3.3.1-78 A boundary (ext) Mon itoring Pump casing Pressure Gray cast iron Raw water (int) Loss of material Fire Water VII,G.A-33 3.3.1-64 B boundary and flow blockage System Pump cas ing Pressure Gray cast iron Raw water (int) Loss of material Selective VII,G.A-51 3.3.1 -72 A boundary Leaching Silencer Pressure Carbon steel Air - outdoor Loss of material External Surfaces VI I. I,A-78 3.3.1-78 A boundary (ext) Mon itoring Silencer Pressure Carbon steel Condensation Loss of material Internal Surfaces VII,E5 .AP-280 3.3.1-95 C boundary (int) in Miscellaneous Piping and Ducting Components

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RBG-47818 Page 11 of 44

Fire Protection - Water System Aging Effect Aging Component Intended Requiring Management NUREG-1801 Table 1 Type Function Material Environment Management Program Item Item Notes Silencer Pressure Carbon steel Exhaust gas Loss of material Internal Surfaces VII. H2.AP-1 04 3.3.1-88 C boundary (int) in Miscellaneous Piping and Ducting Components Sprinkler Pressure Copper alloy Air - indoor None None VII.J .AP-144 3.3.1-114 A boundary >15%Znor> (ext)

Flow control 8%AI Sprinkler Pressure Copper alloy Air - indoor None None VII.J .AP-144 3.3.1-114 A boundary > 15% Zn or> (int) Flow control 8%AI Sprinkler Pressure Copper alloy Raw water (int) Loss of material Fire Water VII.G .A-403 3.3.1-130 B boundary > 15% Zn or> and flow blockage System Flow control 8%AI Sprinkler Pressure Copper alloy Raw water (int) Loss of material Selective VII.G .A-47 3.3.1-72 A boundary > 15% Zn or> Leaching Flow control 8%AI Strainer Filtration Carbon steel Raw water Loss of material Fire Water VII.G .A-33 3.3.1-64 B (ext) System Strainer Filtration Stainless steel Raw water Loss of material Fire Water VII.G .A-55 3.3.1-66 B (ext) System Strainer Pressure Carbon steel Air- indoor Loss of material External Surfaces VII.I.A-77 3.3.1-78 A housing boundary (ext) Monitoring

RBG-47818 Page 12 of 44

Fire Protection - Water System Aging Effect Aging Component Intended Requiring Management NUREG-1801 Table 1 Type Function Material Environment Management Program Item Item Notes Strainer Pressure Carbon steel Raw water (int) Loss of material Fire Water VII.G.A-33 3.3.1-64 B housing boundary and flow blockage System Strainer Pressure Carbon steel Raw water (int) Loss of coating Coating Integrity VII.G .A-416 3.3.1-138 A housing boundary with internal integrity coating Tubing Pressure Copper alloy Fuel oil (int) Loss of material Diesel Fuel VII.G.AP-132 3.3.1-69 A, 303 boundary Monitoring Tubing Pressure Copper alloy Raw water (int) Loss of material Fire Water VII.G.AP-197 3.3.1-64 B boundary and flow blockage System Valve body Pressure Carbon steel Air - indoor Loss of material External Surfaces VII .I.A-77 3.3.1-78 A boundary (ext) Monitoring Valve body Pressure Carbon steel Air - outdoor Loss of material External Surfaces VII .I.A-78 3.3.1-78 A boundary (ext) Monitoring Valve body Pressure Carbon steel Fuel oil (int) Loss of material Diesel Fuel VII .G.AP-234 3.3.1-68 A, 303 boundary Monitoring Valve body Pressure Carbon steel Raw water (int) Loss of material Fire Water VII .G.A-33 3.3.1-64 B boundary and flow blockage System Valve body Pressure Copper alloy Air - indoor None None VII .J.AP-144 3.3.1-114 A boundary (ext) I Valve body Pressure Copper alloy Air - outdoor Loss of material External Surfaces VII .I.AP-1S9 3.3.1-81 A boundary (ext) Monitoring

RBG-47818 Page 13 of 44

Fire Protection - Water System Aging Effect Aging Component Intended Requiring Management NUREG-1801 Table 1 Type Function Material Environment Management Program Item Item Notes Valve body Pressure Copper alloy Raw water Loss of material Fire Water VII.G.AP-197 3.3.1-64 B boundary (ext) and flow blockage System Valve body Pressure Copper alloy Raw water (int) Loss of material Fire Water VII.G.AP-197 3.3.1-64 B boundary and flow blockage System Valve body Pressure Copper alloy Air - indoor None None VII.J .AP-144 3.3.1-114 A boundary > 15% Zn or> (ext) 8%AI Valve body Pressure Copper alloy Air - outdoor Loss of material External Surfaces VII.I.AP-159 3.3.1-81 A boundary > 15% Zn or> (ext) Monitoring 8%AI Valve body Pressure Copper alloy Raw water (int) Loss of material Fire Water VII.G .AP-197 3.3.1-64 B boundary > 15% Zn or> and flow blockage System 8%AI Valve body Pressure Copper alloy Raw water (int) Loss of material Selective VII.G.A-47 3.3.1-72 A boundary > 15% Zn or> Leaching I 8%AI Valve body Pressure Gray cast iron Air - indoor Loss of material External Surfaces VI I. I.A-77 3.3.1-78 A boundary (ext) Mon itoring Valve body Pressure Gray cast iron Air - outdoor Loss of material Externa l Surfaces VII.I.A-78 3.3.1-78 A boundary (ext) Monitoring Valve body Pressure Gray cast iron Raw water (int) Loss of material Fire Water VII.G.A-33 3.3.1-64 B boundary and flow blockage System

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Fire Protection - Water System Aging Effect Aging Component Intended Requiring Management NUREG-1801 Table 1 Type Function Material Environment Management Program Item Item Notes Valve body Pressure Gray cast iron Raw water (int) Loss of material Selective VI LG.A-51 3.3.1-72 A boundary Leaching Valve body Pressure Gray cast iron Raw water (int) Loss of coating Coating Integrity VILG .A-416 3.3.1-138 A boundary with internal integrity coating Valve body Pressure Gray cast iron Raw water (int) Loss of material Coating Integrity VILG.A-415 3.3.1-140 A boundary with internal coating Valve body Pressure Gray cast iron Raw water (in t) Loss of material Coating Integrity VILG.A-414 3.3.1-139 A boundary with internal coating Valve body Pressure Gray cast iron Soil (ext) Loss of material Buried and VILG .AP-198 3.3.1-106 A boundary Underground Piping and Tanks Inspection Valve body Pressure Gray cast iron Soil (ext) Loss of material Selective VILG .A-02 3.3.1-72 A boundary Leaching Valve body Pressure Stainless steel Air - indoor None None VII.J .AP-123 3.3.1-120 A boundary (ext)

Valve body Pressure Stainless steel Raw water (int) Loss of material Fire Water VILG.A-55 3.3.1-66 B boundary and flow blockage System

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RBG-47818 Page 15 of 44 3.3.2.1.7 Fire Protection - Water System Aging Effects Requiring Management The following aging effects associated with the fire protection - water system require management.

Cracking
Cracking - fatigue
Loss of coating integrity
Loss of material
Loss of preload
Reduction of heat transfer
Flow Blockage Question RAI 3.3.2.2.8-1 (Recurring Internal Corrosion)

Background

LRA Section 3.3.2.2.8 states that recurring internal corrosion (RIC) was not identified in auxiliary system components based on a review of past plant operating experience. During its audit, the staff reviewed a report on the evaluation of RIC which states that piping in the fire water system experienced a number of occurrences that warrant evaluation for RIC . The report also states that while leaks and corrosion in the fire water and other systems were documented in condition reports the events were screened out based on: (a) not meeting the frequency of occurrence as described in the definition of RIC ; (b) the corrosion mechanism being indeterminate; (c) the situation was corrected or mitigated by replacement with corrosion resistant materials; or (d) the components were not within the scope of license renewal. Issue It is not clear to the staff that the evaluation of RIC in auxiliary systems was consistent with SRP LR Section 3.3.2.2.8. Specifically:

SRP-LR Section 3.3.2.2.8 discusses "aging effects with the same aging mechanism ," but it does not address RIC on a system-by-system basis nor imply that occurrences of corrosion should be separated into unique groups related to specific systems. The staff acknowledges that it is appropriate to categorize occurrences with the same material , environment, aging effect/mechanism , and program combination . For example, it could be possible that the water from shallow wells is more corrosive than that from the deep wells . If the source of water for system A was from the shallow wells , the source of water from system B was from the deep wells , and there is a basis for concluding that one well source was more corrosive than the other; a case could be made that aging effects in the two systems are unique from a RIC consideration .
An indeterminate aging mechanism is not a sufficient basis to exclude an occurrence from consideration .

During its review of plant specific operating experience, the staff reviewed eight condition reports , as well as several condition reports related to the piping downstream of the jockey pump, and noted that there have been many instances of through wall leakage in fire water system piping . Even if the aging mechanism is not known in some of these occurrences , it appears evident that loss of material resulting in through wall corrosion has exceeded the criteria for RIC to be applicable to the Fire Protection - Water System program .

Replacement of piping (with either like for like or corrosion resistant materials) should not result in removing an occurrence from consideration . Unless the corrective actions address all of the similarly susceptible

RBG-47818 Page 16 of 44 components by either a global material change or overall change to the environment, the aging effect/mechanism will still be active and should be addressed as RIC . Request In order to demonstrate that RIC is not applicable to in scope auxiliary components , provide the complete list of occurrences of 50 percent or greater internal loss of material within the evaluated time period. The list should describe the occurrence , aging mechanism or assumed aging mechanism , and date of discovery. In light of the discussion in the issue portion of this RAI , provide a basis for why each occurrence should not be considered an appropriate data point for consideration of RIC . Alternatively, if after evaluating the occurrences in light of the discussion in the issue portion of this RAI it is determined that RIC has occurred in the in scope auxiliary systems, state the aging mechanism and applicable AMP(s) In addition , state what changes will be incorporated in the LRA sufficient to address the recommendations in SRP LR Section 3.3.2.2.8.

Response

Based on the results of a review of plant-specific operating experience in the years 2006 to 2016, recurring internal corrosion as defined in LR-ISG-2012-02 has occurred in portions of normally water-filled carbon steel piping of the fire protection - water system . The applicable aging effect is loss of material due to corrosion mechanisms of microbiologically influenced corrosion (MIC) or general, crevice, or pitting corrosion . The Fire Water System Program will be used to manage loss of material in piping exposed to raw water in the fire protection - water system . Augmented examination provisions will be added, which will include volumetric wall thickness evaluations using ultrasonic testing (UT) or radiography. These examinations will be performed at a minimum of five locations in piping susceptible to these corrosion mechanisms every refueling cycle until the frequency of occurrences of loss of material no longer meets the criteria for recurring internal corrosion . Five inspections in each refueling cycle will result in 25 inspections in a 10-year period . LR-ISG-2012-02, Section B, recommends a sample size of 25 in each 1O-year period for inspections that are conducted in accordance with similar sampling-based programs such as in NUREG-1801 , AMP XI.M38 , "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components." Selection of components for inspection will be biased toward locations most susceptible to corrosion mechanisms considering the characteristics that are conducive to corrosion . The selected locations will provide a representative sample of the piping system and will be chosen based on configuration , flow conditions , and operating history. The most susceptible locations are to be selected for inspection . RBS will utilize ultrasonic testing (UT) or radiography of the fire protection - water system piping to determine wall thickness and monitor locations where loss of material is occurring to ensure repairs or replacements are performed prior to loss of intended function . Ultrasonic testing is an industry accepted and recognized method for detecting loss of material prior to loss of component intended function . Radiography can be used for those configurations where UT is not effective. Evaluation of the inspection results will include (1) comparison to the nominal wall thickness or previous wall thickness measurements to determine rate of corrosion , (2) comparison to the design minimum allowable wall thickness to determine acceptability of the component for continued use, and (3) determination of a schedule for reinspection . For areas of piping that are found with substantial corrosion and returned to service , the remaining service life will be calculated and the piping will be re-examined prior to the end of calculated service life. The scope of these augmented examinations will be expanded if substantial corrosion is detected during inspections. Scope expansion includes additional locations for sampling , such as similar components in other

RBG-47818 Page 17 of 44 parts of the system . Corrosion will be considered substantial if the component does not meet plant-specific acceptance criteria (such as, wall thickness required by the design code for the component) or experiences a reduction in wall thickness greater than 50 percent of nominal wall thickness . For through-wall leaks and material loss greater than 50 percent of nominal wall thickness , four additional locations will be examined during the next refueling cycle . Where the identified material loss is 30 percent to 50 percent of nominal wall thickness and the calculated remaining life is less than two years , two additional locations will be examined during the next refueling cycle . Mitigation and monitoring activities have been effective in managing loss of material in the fire protection - water system as demonstrated by the fact that loss of material , including the consideration of structural integrity, has not resulted in the loss of a component's ability to support system pressure and flow requirements . A 2016 program replaced much of the piping near the jockey pump. This piping had experienced more than normal corrosion because periodic operation of the jockey pump replenished the oxygen in the water exacerbating corrosion rates . The augmented volumetric examinations added to the Fire Water System Program (B.1.20) will manage loss of material due to recurring internal corrosion during the period of extended operation . Changes to the RBS LRA follow with additions underlined and deletions lined through . 3.3.2.2.8 Loss of Material due to Recurring Internal Corrosion A review of 10 years of plant operating experience identified no conditions of recurring internal corrosion as defined in LR-ISG 2012-02, Section A , in the piping components of the auxiliary systems in the scope of license renewal.carbon steel piping exposed to raw water. The Fire Water System Program will manage loss of material due to recurring internal corrosion for piping and piping components through augmented periodic examinations . The Fire Water System Program will include periodic examinations at a minimum of five locations at least once every refueling cycle during the period of extended operation. Wall thickness measurements at susceptible locations will provide a representative sample . The scope of these augmented examinations will be expanded if substantial corrosion is detected during inspection .

RBG-47818 Page 18 of 44 Table 3.3.1 : Auxiliary Systems Aging Further Item Aging Effect! Management Evaluation Number Component Mechanism Programs Recommended Discussion 3.3.1-127 Metallic piping , Loss of material A plant-specific Yes , plant-specific ReGbiFFiR§ iRteFRal G9FF9si9R INas R9t piping due ag ing iEleRtifieEl iR tRe RBS abl*i liaFY systems iR components , to recurring management tRe SG9f3e 9f IiGeRSe FeRewal. and ta nks internal prog ram is to be For carbon steel l2il2ing in the fire exposed to raw corrosion evaluated to I2rotection - water system , the Fire Water water or address System Program manages loss of material waste water recu rring due to recurring internal corrosion . internal .:. corrosion See Section 3.3.2.2.8.

         '-----

Table 3.3.2-7: Fire Protection - Water System Aging Effect Aging Component Intended Requiring Management NUREG- Table 1 Type Function Material Environment Management Programs 1801 Item Item Notes Pil2ing Pressure Carbon Raw water Loss of Fire Water VII .G.A-400 3.3.1-127 E bounda!:y steel (int) material due to System recurring internal corrosion

RBG-47818 Page 19 of 44 A.1.20 Fire Water System Program Testing or replacement of sprinkler heads that have been in service for 50 years is performed in accordance with the 2011 Edition of NFPA 25. Portions of the water-based fire water system that (a) are normally dry, but periodically subject to flow (e.g., downstream of the deluge valve in a deluge system) and (b) allow water to collect are subject to augmented examination beyond that specified in NFPA 25. The augmented examinations for the portions of normally dry piping that are periodically wetted include (a) periodic full flow tests at the design pressure and flow rate , or internal inspections, and (b) volumetric wall thickness evaluations. Augmented examinations for the system include periodic volumetric wall thickness evaluations, at a minimum rate of 5 inspections in each refueling cycle The Fire Water System Program will be enhanced as follows .

Revise Fire Water System Program procedures to conduct augmented volumetric wall thickness examinations of fire water system piping. Inspections will be performed during the period of extended operation as long as the frequency of occurrence of loss of material meets the criteria for recurring internal corrosion . Procedures shall specify wall thickness measurements at a minimum of five selected locations per refueling cycle . The number of augmented examinations will be increased if substantial corrosion is detected during inspections. Corrosion will be considered substantial if the component does not meet plant-specific acceptance criteria (such as the minimum wall thickness required by the design code) or experiences a reduction in wall thickness greater than 50 percent of nominal wall thickness. For through-wall leaks and material loss greater than 50 percent of nominal wall thickness , four additional locations will be examined during the next refueling cycle . Where the identified material loss is 30 percent to 50 percent of nominal wall thickness and the calculated remaining life is less than two years , two additional locations will be examined during the next refueling cycle .

8.1.20 FIRE WATER SYSTEM Program Description Testing or replacement of sprinkler heads that have been in service for 50 years is performed in accordance with the 2011 Edition of NFPA 25. Portions of the water-based fire water system that (a) are normally dry, but periodically subject to flow (e.g., downstream of the deluge valve in a deluge system) and (b) allow water to collect are subject to augmented examination beyond that specified in NFPA 25. The augmented examinations for the portions of normally dry piping that are periodically wetted include (a) periodic full flow tests at the design pressure and flow rate, or internal inspections, and (b) volumetric wall thickness evaluations. Augmented examinations for the system include periodic volumetric wall thickness evaluations, at a minimum rate of 5 inspections in each refueling cycle .

RBG-47818 Page 20 of 44 Enhancements The following enhancements will be implemented prior to the period of extended operation . Element Affected Enhancement

4. Detection of Aging Revise Fire Water System Program I2rocedures to conduct Effects augmented volumetric wall thickness examinations of fire water system l2il2ing . Insl2ections will be l2erformed during the l2eriod of extended ol2eration as long as the freguency of occurrence of loss of material meets the criteria for recurring internal corrosion . Procedures shall sl2ecify wall thickness measurements at a minimum of five selected locations l2er refueling cycle. The number of augmented examinations will be increased if substantial corrosion is detected during insl2ections. Corrosion will be considered substantial if the coml2onent does not meet I2lant-sl2ecific accel2tance criteria (such as the minimum wall thickness reguired by the design code) or eXl2eriences a reduction in wall thickness greater than 50 l2ercent of nominal wall thickness . For through-wall leaks and material loss gre ater than 50 l2ercent of nom inal wall th ickness , fou r additiona l locations will be exam ined during the next refuel ing cycle . Where the identified materi al loss is 30 l2ercent to 50 l2ercent of nominal wa ll thickness and the calcu lated remaining life is less than two years, two add itional locations will be exam ined duri ng the next refueling cycle.

Question RAI 3.6.2.2.3-1 (TRP 104 Transmission Conductors and Switchyard Buses)

Background

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 Connection 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 Connection due to Oxidation or Loss of Pre-load could occur in transmission conductors and connections, 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 and connections , and switchyard bus and connections. Table 3.6.1 of the LRA, line item number 3.6.1-6 identifies the component as : "Switchyard bus and connections composed of aluminum , copper, bronze, stainless steel, galvanized steel,

RBG-47818 Page 21 of 44 exposed to air-outdoor." The corresponding item in Table 3.6.2 of the LRA identifies the material as: "Aluminum , steel , steel alloy." Table 3.6.1 of the LRA, item 3.6.1-20, describes the component as "transmission conductors ." The corresponding Table 3.6.2, item 3.6.1-20 lists the component as "transmission connectors ." Issue

The staff noted a discrepancy between LRA table 3.6.1 and table 3.6.2 in describing the material for switchyard bus and connections for line item 3.6.1-6. Table 3.6.2 of the LRA is inconsistent with table 3.6.1 in that it has omitted copper, bronze, stainless steel , and galvanized steel in the list of materials that make up this component. It is not clear whether this discrepancy is based on a plant specific evaluation which has determined a lack of such material for switchyard bus and connections at RBS .
The staff also noted a discrepancy in the applicant's LRA Table 3.6.2, Item 3.6.1-20 that lists the component as "transmission connectors ." This item corresponds to the associated Table 3.6.1, item 3.6.1-20, which describes the component as "transmission conductors ."

Request

1. Clarify the discrepancy between LRA table 3.6.1 items 3.6.1-6 with the corresponding table 3.6.2 components that omitted copper, bronze, stainless steel, and galvanized steel in the list of material that make up this component.

2. Justify the discrepancy or revise LRA Table 3.6.2, items 3.6.1-20, "Component Type" column to reflect the appropriate description as "Transmission conductors ," consistent with Table 3.6.1 , item 3.6.1-20.

Response

Part 1 With the exception of the "discussion" column , LRA Table 3.6.1 is taken verbatim from NUREG-1800, Table 3.6-1 . The apparent discrepancy reflects the results of a plant-specific evaluation that determined the specific material for switchyard bus and connections at the River Bend Station (RBS) . As discussed below, LRA Table 3.6.2 addresses site-specific materials for RBS . The RBS 230 kV switchyard bus (both large and small diameter) is aluminum tube. Station post (high-voltage) insulators support the switchyard bus. Insulator fastening hardware is cast aluminum and all bolted connections are stainless steel. The bus-to-bus connections are welded and bolted connections are limited to expansion joints or the connections to flex conductors . Flexible conductor bolted connections are included with the switchyard bus commodity and these connections are aluminum , steel, and stainless steel. Based on this information , the materials associated with the RBS switchyard bus and connections are aluminum , cast aluminum , steel , and stainless steel.* The RBS materials listed in LRA Table 3.6.2 for switchyard bus and connections are aluminum , steel , and steel alloy. Cast aluminum is aluminum and stainless steel is steel alloy. The materials listed in Table 3.6-1 of NUREG-1800 and in LRA Table 3.6.1, Item 3.6.1-6, bound the materials used at RBS for the switchyard bus and connections commodity group. Therefore , no changes are necessary for LRA Table 3.6.2 or Table 3.6.1, Item 3.6.1-6.

RBG-47818 Enclosure 1 Page 22 of 44 Part 2 The last line of LRA Table 3.6.2 has a discrepancy that is corrected with this RAI response . The last line of LRA Table 3.6.2, which references Table 3.6.1, Item 3.6.1-20, should have shown transmission conductors ; not connectors in the Component Type column to address transmission conductors of this material. Transmission connectors are addressed in LRA Table 3.6.2, item 3.6.1-5. The changes to LRA Table 3.6.2 follow with additions underlined and deletions lined through . Table 3.6.2: Electrical and I&C Components Structure and/or Aging Effect Aging Component or Intended Requiring Management NUREG- Table 1 Commodity Function Material Environment Management Program 1801 Item Item Notes Transmission

 'nn Aluminum conductor

.... onductors VIALP-46 aluminum transmission CE Air - outdoor None None VI.A-16 3.6.1-20 A

  *n,..,                              alloy (LP-08) reinforced r.onductors for (ACAR)

SSO recovery) Question 4.7.1-1 (TRP 120 Erosion of Main Steam Line Flow Restrictors)

Background

During the audit, the staff noted that General Electric Hitachi (GEH) performed an analysis (GEH Proprietary Report 003N4606, as incorporated in RBS Specific Report RBS-ME-16-00008 , Rev.

0) for the erosion rate of the main steam line flow restrictors to evaluate the associated Time-Limited Aging Analysis (TLAA) discussed in the LRA Section 4.7.1. The TLAA has been evaluated in accordance with 10 CFR 54.21 (c)(ii) .

LRA Sections 4.7.1 and the USAR supplement for the TLAA in LRA Section A.2 .5.1 state that:

           "Entergy evaluated the erosion rate for the main steam flow restrictors. The evaluation considered the specific material for the flow restrictors and determined the expected erosion rate . The evaluation determined the expected erosion rate would be much less than the conservative value in the USAR. Using the lower expected corrosion rate , the increase in flow restrictor diameter after 60 years would result in a choked flow increase of less than the 5 percent value identified as acceptable in USAR Section 5.4.4.4."

SRP-LR Section 4.7.3.1.2, states that an applicant may revise the TLAA by recognizing and reevaluating any overly conservative conditions and assumptions. This section also states that the applicant shall provide a sufficient description of the analysis and document the results of the reanalysis to show that it is satisfactory for the 60 year period.

RBG-47818 Page 23 of 44 SRP-LR Section 4.7.2.2, which contains the FSAR supplement acceptance criteria for plant-specific TLAAs , states, "the specific criterion for meeting 10 CFR 54.21 (d) is: The summary description of the evaluation of TLAAs for the period of extended operation in the FSAR supplement is appropriate such that later changes can be controlled by 10 CFR 50.59. The description contains information associated with the TLAAs regarding the basis for determining that the applicant has made the demonstration required by 10 CFR 54.21 (c)(1 )." Issue LRA Sections 4.7.1 and A.2 .5.1 do not appear to include sufficient information or analysis details to demonstrate the applicant's basis for dispositioning the TLAA in accordance with 10 CFR 54.21 (c)(1 )(ii) other than providing the 5 percent acceptance criterion for flow increase used in the analysis . Such details are necessary to satisfy SRP-LR Section 4.7.3.1.2, SRP-LR Section 4.7 .2.2, and 10 CFR 54.21(d) . Request Clarify which assumptions and conservatisms have changed in the new GEH main steam line flow restrictor wear and flow analysis and describe how those assumptions or conservatisms have changed from the prior wear and flow analysis used in the CLB to assess the flow restrictors . As part of this clarification , provide the wear-dependent flow rate used in the new analysis and the calculated percent increase in steam flow value for the restrictors , as projected to the end of the period of extended operation . Amend the USAR Supplement in LRA Section A.2 .5.1 to include this type of information , as necessary. Alternatively , submit the referenced GEH report, along with an appropriate proprietary affidavit for withholding information pursuant to 10 CFR 2.390, and amend the USAR Supplement section to reference the applicable GEH report for the TLAA, as necessary. Response provides the proprietary version of the GEH report that evaluated potential erosion of the main steam line flow restrictor and an affidavit that provides the basis for withholding proprietary information pursuant to 10 CFR 2.390. Enclosure 3 provides the non-proprietary version of the GEH report. The changes to LRA Section A.2 .5.1 follow with additions underlined . A.2.S.1 Erosion of Main Steam Line Flow Restrictors USAR Section 5.4.4.4 states that flow restrictors erode very slowly and conservatively postulates that even with an erosion rate of 0.004 inches per year, the increase in choked flow after 40 years would be no more than 5 percent. Entergy evaluated the erosion rate for the main steam flow restrictors in RBS-ME-16-00008 "GEH 003N4606, Rev. 2, River Bend Station Unit 1 Main Steam Flow Restrictors, April 2016 (Proprietary)" (EC-RBS-0000075698) . The evaluation considered the specific material for the flow re.strictors and determined the expected erosion rate . Th~ evaluation determined the expected erosion rate would be much less than the conservative value in the USAR. Using the lower expected corrosion rate, the increase in flow restrictor diameter after 60 years would result in a choked flow increase of less than the 5 percent value identified as acceptable in USAR Section 5.4.4.4. This analysis has been projected through the period of extended operation in accordance with 10 CFR 54.21 (c)(1 )(ii) .

RBG-47818 Page 24 of 44 Question RAI B.1.1-1 (TRP 30 Aboveground Tanks)

Background

LRA Section B.1.1 states the following in regard to preventive actions for managing aging effects associated with the condensate storage tank (CST). Preventive measures to mitigate corrosion were applied during construction , such as using the appropriate materials and use of a protective multi-layer vapor barrier beneath the tank . The inner volume of the concrete ring foundation is filled with clean dry sand , which is sloped downward from the tank center to the tank exterior. The protective multi-layer vapor barrier beneath the tank serves as a seal at the concrete-to-tank interface. GALL Report AMP XI.M29 , "Aboveground Metallic Tanks ," as modified by LR ISG 2012 02, "Aging Management of Internal Surfaces, Fire Water Systems, Atmospheric Storage Tanks , and Corrosion Under Insulation," (hereinafter referred to as AMP XI.M29) recommends :

That caulking or sealant be installed at the tank to concrete foundation interface.
Periodic visual inspections at each outage to confirm that the caulking or sealant is intact.
Periodic volumetric thickness examination of the bottom of the tank each 10 year period commencing 10 years prior to the end of the period of extended operation .

Issue Although LRA Section B.1.1 states that the sand under the tank is dry, the sand could have become wetted due to moisture absorption from ground water penetrating through the vapor barrier or moisture intrusion from the tank to concrete foundation interface. In addition, based on a review of the CST construction drawing , the staff noted that there is an internal lip on the inside ring of the CST foundation . As a result, if water were to penetrate at either location , water could accumulate through the thickness of sand. Information Notice 86-99, Supplement 1, "Degradation of Steel Containments," addresses loss of material from carbon steel drywells in contact with a sand bed . During the audits the staff:

Noted that there is no caulking installed at the tank to concrete foundation interface.
Did not identify any plant specific procedures requiring an inspection of the multi layer vapor barrier at the interface between the CST tank sides and concrete foundation .
Conducted a walkdown of the CST and noted that: (a) the vapor barrier installed between the tank bottom and concrete/sand bed extended in general 4 inches beyond the side of the tank; (b) the upper layer of the vapor barrier is severely weathered with fibers showing ; (c) there is evidence of delamination between layers of the vapor barrier; and (d) approximately 40 percent of the perimeter of the tank is adjacent to a curt:> that could allow water to accumulate above the height of the vapor barrier.

As a result of the potential for water to accumulate in the sand under the tank, lack of caulking at the tank"" to concrete interface, and the degraded condition of the edges of the vapor barrier, the staff has determined that loss of material due to pitting and crevice corrosion could be occurring on the tank bottom . AMP XI.M29 does not include any recommendations for the quantity of data

RBG-47818 Page 25 of 44 points or location of the bottom thickness measurements. However, given that the preventive action recommendations of AMP XI.M29 are not met, the staff requires this information to complete its evaluation of the effectiveness of the Aboveground Metallic Tanks program . It should be noted that the low-frequency electromagnetic testing (LFET) technique can be capable of scanning the entire bottom of the tank in order to detect discrete locations where augmented bottom thickness measurements should be conducted . The staff's evaluation of the use of this technique for stainless steel tanks is documented in NUREG 2172, "Safety Evaluation Report Related to the License Renewal of Calloway Plant, Unit 1," Section 3.0.3.2.8. The staff cannot complete its review of the Aboveground Metallic Tanks program without reviewing the changes to LRA Section B.1.1 necessary to address potential loss of material on the bottom external surfaces of the CST. Request

1. State the periodicity, method , and extent of the inspections of the multi layer vapor barrier interface between the CST tank sides and concrete foundation .

2. State the quantity and location of data points for the periodic bottom thickness measurements .

In addition , state the basis for why the quantity and location of data points will be sufficient to detect loss of material due to pitting or crevice corrosion .

3. If the LFET technique will be used , state the criteria for followup discrete tank thickness measurements .

4. If other scanning techniques will be used , state the basis for the effectiveness of these techniques in detecting loss of material due to pitting or crevice corrosion and the criteria for follow-up discrete tank thickness measurements.

Response

1. As indicated in LRA Section B.1.1, the RBS Aboveground Metallic Tanks Program is a new program that will be consistent with the program described in NUREG-1801 , Section XI.M29 ,

Aboveground Metallic Tanks , as modified by LR-ISG -2012-02. Therefore, visual inspection of the multi-layer vapor barrier that seals the interface between the tank and its foundation will be conducted in accordance with NUREG-1801 , Section XI.M29, Above ground Metallic Tanks , as modified by LR-ISG-2012-02. The entire outer edge of the vapor barrier will be visually inspected at least once per refueling cycle . Deficiencies in the seal found during inspection will be entered into the corrective action program for evaluation and corrective action to mitigate the potential for corrosion of the bottom surface of the tank.

2. Condensate storage tank (CST) bottom thickness measurements will be obtained using one of the following two methods.

1) Ultrasonic testing (UT) will be used to inspect a minimum of 25% of the outer 18 inches of tank bottom on a 6" grid pattern or less. Approximately 40 percent of the perimeter of the tank is adjacent to a curb that could allow water to accumulate against the outside wall of the tank above the height of the tank foundation . As a result, at least 50% of the tank bottom thickness measurements will be adjacent to the area enclosed by the outside curb.

The inside diameter of the concrete foundation is approximately 9 inches inside the outer diameter of the tank wall. Inspecting the outer 18 inches of tank bottom encompasses 9 inches of concrete bearing surface and 9 inches of tank bottom resting on sand fill.

2) A scanning technique such as low-frequency electromagnetic testing (LFET) will be used to scan the outer 18 inches of the tank bottom adjacent to the tank wall for the entire circumference . All areas found potentially less than the minimum design thickness will be

RBG-47818 Page 26 of 44 inspected using UT. The tank bottom is sloped such that any water intrusion under the tank would collect in the outer 18 inches, making that area the most susceptible area for corrosion . Therefore , inspection of the outer 18 inches will provide reasonable assurance that loss of material on the tank bottom is not occurring at a rate that will prevent the CST from performing its intended function during the period of extended operation . The Aboveground Metallic Tanks Program is revised to include volumetric inspections of the tank bottom near the outer circumference.

3. If the LFET technique is used , follow-up discrete tank thickness measurements using UT will be performed on all areas found potentially less than the minimum design thickness .

4. The Aboveground Metallic Tanks Program is a new program that will be implemented prior to the period of extended operation. Scanning techniques other than LFET may be considered during implementation and evaluated for the ability to detect loss of material due to pitting and crevice corrosion . Follow-up discrete tank thickness measurements using UT will be performed on all areas found to be potentially less than the minimum design thickness . Regardless of technique used , CST inspections will be performed in accordance with NUREG-1801 , Section XI.M29 , as modified by LR-ISG-2012-02.

Changes to LRA A.1 .1 and B.1.1 follow with additions underlined and deletions lined through . A.1.1 Aboveground Metallic Tanks The Aboveground Metallic Tanks Program manages loss of material for the nonsafety-related aluminum condensate storage tank (CST) , which is located outdoors on sand and concrete . Preventive measures to mitigate corrosion were applied during construction , such as using the appropriate materials and use of a protective multi-layer vapor barrier beneath the tank. The inner volume of the concrete ring foundation is filled with clean dry sand , which is sloped downward from the tank center to the tank exterior. The protective multi-layer vapor barrier beneath the tank serves as a seal at the concrete-to-tank interface. There are no indoor tanks included in this program . Interior and exterior surfaces of the CST will be inspected . The program will also perform Inspections include ultrasonic testing (UT) of the CST tank bottom to assess the thickness against the design specified thickness during each 1O-year period starting 10 years before the period of extended operation and periodic visual inspection of the seal between the tank bottom and concrete foundation at least once per refueling cycle . Ultrasonic thickness measurements are performed by using one of two methods: 1) UT will be used to inspect a minimum of 25% of the outer 18 inches of tank bottom on a 6" grid pattern or less. At least 50% of the tank bottom thickness measurements will be on the tank bottom adjacent to the area enclosed by the outside curb. 2) A scanning technique such as low-frequency electromagnetic testing (LFET) will be used to scan the outer 18 inches of the tank bottom adjacent to the tank wall for the entire circumference . All areas found to be potentially less than the minimum design thickness will be inspected with UT.

RBG-47818 Page 27 of 44 8.1.1 Aboveground Metallic Tanks Program Description The Aboveground Metallic Tanks Program is a new program that will manage loss of material for the non-safety-related aluminum condensate storage tank (CST) , which is located outdoors on sand and concrete . Preventive measures to mitigate corrosion were applied during construction , such as using the appropriate materials and use of a protective multi-layer vapor barrier beneath the tank. The inner volume of the concrete ring foundation is filled with clean dry sand , which is sloped downward from the tank center to the tank exterior. The protective multi-layer vapor barrier beneath the tank serves as a seal at the concrete-to-tank interface. There are no indoor tanks included in this program . Interior and exterior surfaces of the CST will be inspected . The program will also perform Inspections include ultrasonic testing (UT) of the CST tank bottom to assess the thickness against the design specified thickness whenever the tank is drained Gfand during each 10-year period starting 10 years before the period of extended operation and periodic visual inspection of the seal between the tank bottom and concrete foundation at least once per refueling cycle . Ultrasonic thickness measurements are performed by using one of two methods: 1) UT will be used to inspect a minimum of 25% of the outer 18 inches of tank bottom on a 6" grid pattern or less. At least 50% of the tank bottom thickness measurements will be on the tank bottom adjacent to the area enclosed by the outside curb. 2) A scanning technique such as low-frequency electromagnetic testing (LFET) will be used to scan the outer 18 inches of the tank bottom adjacent to the tank wall for the entire circumference . All areas found to be potentially less than the minimum design thickness will be inspected with UT. Question RAI 8.1 .1-2 (TRP 30 Aboveground Metallic Tanks)

Background

LRA Section A.1 .1 does not state that periodic visual inspections will be conducted to monitor the condition of the sealant (i.e., in this case , the vapor barrier interface between the CST tank sides and concrete foundation) installed at the CST tank to concrete foundation interface. 10 CFR 54.21 (d) states , U[t]he FSAR supplement for the facility must contain a summary description of the programs and activities for managing the effects of aging , .. " GALL Report AMP XI.M29 , as modified by LR ISG 2012 02 , Table 3.0 1, uFSAR Supplement for Aging Management of Applicable Systems," states that periodic visual inspections should be conducted to monitor the condition of the sealant (i.e., in this case, the vapor barrier interface between the CST tank sides and concrete foundation) installed at the CST tank to concrete foundation interface. Issue The licensing basis for this program for the period of extended operation will not be consistent with staff issued guidance documents if the USAR supplement does not include these inspections.

RBG-47818 Page 28 of 44 In addition , due to the potential for water to accumulate in the sand under the tank, lack of caulking at the tank"" to concrete interface, and the degraded condition of the edges of the vapor barrier, the staff has determined that the level of detail in the USAR supplement associated with ultrasonic thickness measurements of the CST tank bottom is not sufficient. As discussed in RAI B.1.1-1 , additional detail on the quantity of data points and location of the bottom thickness measurements should be included in the USAR supplement for the Aboveground Metallic Tanks program. The staff cannot complete its review of the Aboveground Metallic Tanks program USAR Supplement without reviewing the changes to LRA Section A.1 .1 necessary to address inspections of the vapor barrier and additional detail associated with bottom thickness measurements of the CST. Request State the basis for why LRA Section A.1 .1 does not cite the periodic visual inspections of the vapor barrier at the CST tank to concrete foundation interface. Alternatively, what changes will be incorporated into LRA Section A.1 .1 to include these requirements? What changes will be incorporated into the USAR supplement associated with the quantity of data points and location of the bottom thickness measurements? If a scanning technique will be used , include the criteria for follow-up discrete tank thickness measurements .

Response

LRA Section A.1 .1 is revised to include periodic visual inspections of the vapor barrier at the CST tank to concrete foundation interface. In addition, LRA Section A.1 .1 is revised to include the quantity of data points and location of the bottom thickness measurements and the criteria for follow-up discrete tank thickness measurements if a scanning technique is used . Because the issues discussed in this RAI are directly related to the issues discussed in RAI B.1.1-1 , revisions to LRA Section A.1 .1 discussed in this response are provided in the response to RAI B.1.1-1. Question RAI B.1.10-3 (TRP 9 BWR Vessel Internals)

Background

The applicant provides its response to specific applicant action items (Mis) on specific EPRI BWRVIP reports in Appendix C of the LRA. The "scope of program" element and program evaluation report for the AMP identify that the applicant is using the inspection and evaluation guidelines in EPRI Technical Report (TR) BWRVIP-139-A as the basis for inspecting components in the plant's steam dryer assembly. The staff issued its basis for using the guidelines in BWRVIP-139-A, and Appendix B of the report, to manage aging in BWR steam dryer assembly components in a staff-issued safety evaluation dated November 8, 2016 (ML16180A462). The staff's safety evaluation includes three Mis that would need to be responded to in order to justify use of TR BWRVIP-139-A for aging management of the steam dryer assemblies during the period of extended operation.

RBG-47818 Page 29 of 44 Issue The applicant has not included any responses to the Mis for the TR BWRVIP-139-A methodology in Appendix C of the LRA. Request Provide responses to the Mis or justify why Appendix C of the LRA does not include any responses to the Mis that apply to EPRI Report BWRVI P-139-A and Appendix B of the report.

Response

License renewal application changes are identified below to include references to BWRVIP-139, Revision 1-A and responses to the associated applicant action items The changes to LRA Section A.1 .10, Section 8.1 .10 and Appendix C follow with additions underlined . Add to Section A.1 .10 at the end of the 3rd paragraph . RBS follows the guidelines of BWRVIP-139 , Revision 1-A for inspection and evaluation of steam dryer components . Add to Section B.1.10 at the end of the 3 rd paragraph in program description . RBS follows the guidelines of BWRVIP-139 , Revision 1-A for inspection and evaluation of steam dryer components . Add to listing on page C-2 of Appendix C. BWRVIP-139 Steam Dryer Inspection and Flaw Evaluation Guidelines , Revision 1-A Add to end oftable in Appendix C (next page)

RBG-47818 Page 30 of 44 Action Item Description Response BWRVIP-139 Steam Dr~er Ins(2ection and Flaw Evaluation Guidelines, Revision 1-A BWRVIP-139, Rev. 1-A (1)

a. BWR a(2(2licants for license renewal are The River Bend BWRl6 steam dr~er reguested to (2erform a review of the CLB is s(2ecificall~ identified in Section and design basis of their facilities to 2.3.12 and the design is included in determine whether there are an~ design the evaluations documented in differences in their stream dr~er designs or BWRVIP-139 Revision 1-A. No aging steam dr~er-related OE that is a(2(2licable for effects have been identified be~ond their BWR design . S(2ecificall~ , BWR those identified in BWRVIP-139, a(2(2licants for license renewal are reguested Revision 1-A.

to (2erform a review of the CLB and design basis of their facilities to determine whether there are an~ additional aging effects that might be a(2(2licable to the designs of their BWR steam dr~er assemblies in addition to those that are mentioned as being a(2(2licable aging effects/mechanisms reguiring management (AERMs) in BWRVIP-139, A(2(2endix B.

b. For those BWR license renewal a(2(2licants that identif~ additional AERMs be~ond those listed in BWRVIP-139, A(2(2endix B, the a(2(2licants should include a(2(2licable GALL-based or (2lant-s(2ecific AMR items in the LRAs that identif~ the additional aging effects that are a(2(2licable to their steam deyer designs , and should identif~ and iustif~

the AMP or TLM that will be used to manage those aging effects during the (2eriod of extended o(2eration , as reguired b~ 10 CFR 54.21 (a)(3).

RBG-47818 Page 31 of 44 Action Item Description Response BWRVIP-139 Rev. 1-A (2) Paragral2h 54.21(d) of 10 CFR Part 54 (the LR LRA Section A.1 .10 indicates that Rule) reguires a license renewal al2l2licant to include RBS follows the guidelines of a final safety analysis rel20rt (FSAR, as may have BWRVI P-139 , Revision 1-A for been ul2dated to a UFSAR or USAR) SUl2l2lement insl2ection and evaluation of steam summary descril2tion for each AMP and TLAA that dryer coml2onents . is credited for aging management of the al2l2licant's facility . The LR Rule does not regui re a BWR license renewal al2l2licant to include an FSAR, UFSAR, or USAR SUl2l2lement summary descril2tion for each BWRVIP rel20rt that is within the SCOl2e of an al2l2licant's BWR RVI management I2rogram . BWR license renewal al2l2licants that will be al2l2lying the BWRVI P-139 rel20rt and Al2l2endix B of the rel20rt to manage age-related degradation in the BWR steam dryers are reguested to describe or reference in the FSAR, UFSAR, or USAR SUl2l2lement summary descril2tion for the BWR RVI management I2rogram how the BWRVIP- 139 rel20rt and Al2l2endix B of the rel20rt will be used to manage age-related degradation in the I2lant's steam dryer during the l2eriod of extended ol2eration. BWRVIP-139 Rev. 1-A (3) License renewal al2l2licants are reguired by 10 CFR No TLAAs were identified for the RBS 54.21 to identify all analyses in the CLB that steam dryer. conform to the six criteria for defining TLAAs in 10 CFR 54.3(a) . If the CLB does include a steam dryer analysis , which conforms to the definition of a TLAA, the al2l2licant is reguired to :

a. include the TLAA in the LRA in accordance with the reguirements in 10 CFR 54.21(c)(1) ;

b. demonstrate that the TLAA will be accel2table for the l2eriod of extended ol2eration in accordance with one of three criteria for accel2ting TLAAs in 10 CFR 54.21 (c)(1)(i) , (ii) , or (i ii) ; and

c. include an FSAR, UFSAR or USAR SUl2l2lement summary descril2tion for the TLAA in the LRA, in accordance with 10 CFR 54.21 (d).

These bases are consistent with the guidelines for formatting LRAs in NEI 95-10 , Revision 6.

RBG-47818 Page 32 of 44 Question RAI B.1.20-1 (TRP 28 Fire Water System)

Background

LRA Section B.1.20 states an exception to conducting flow testing in accordance with NFPA 25, "Standard for the Inspection , Testing , and Maintenance of Water Based Fire Protection Systems," Section 6.3.1, "Flow Tests ." The basis for the exception is that fire hoses are tested every 3 years and main drain tests are conducted on 20 percent of the standpipes and risers every refueling outage. Issue The staff lacks sufficient information to conclude that the proposed alternatives to NFPA 25, Section 6.3.1 provide a sufficient basis for the exception . During the audit, the staff reviewed the fire hose test procedure . The acceptance criteria for the test is that after flowing 2 to 3 gallons into a container with the valve partially open , the test personnel verifies that the "flow is free of any blockage." The staff noted that: (a) the valve is only partially opened and as a result, it is possible that insufficient flow velocity would be established to result in fouling products transferring to the bucket; and (b) the results cannot be trended because there is no quantification of the fouling products. The results of flow tests conducted in accordance with NFPA 25, Section 6.3.1 can be trended (i.e., design pressure, flow) and therefore provide advance warning of potential fouling issues. The main drain tests are insufficient as a basis for the exception because AMP XI.M27 , "Fire Water System ," recommends that both main drain tests and the Section 6.3.1 flow tests be conducted . The staff cannot complete its review of the Fire Water System program without reviewing the changes to LRA Section B.1.20 necessary to address potential enhancements to the program and changes to the basis for this exception. Request State what alternative testing with quantitative (capable of being trended) results will be conducted in lieu of flow testing the hydraulically most remote hose connection at each zone of an automatic standpipe system . What changes will be incorporated into LRA Section 8.1 .20 to address this testing?

Response

Full flow testing of hose connections in the auxiliary building or fuel building is not practical because of the logistics involved in handling the large volume of water discharged during the test. Discharging the water from inside of the auxiliary building would require breaching the secondary containment pressure boundary to route a hose to an outside area . For any location inside the radiologically controlled area, the water would have to be transported out of the building or possibly processed as radiological waste . In lieu of flow testing the hydraulically most remote hose connection of the automatic standpipe system , the Fire Water System Program will be enhanced to perform a full flow test on hose rack HR96, Control Building 135'0" elevation stairwell in accordance with NFPA-25 (2011 Edition) Section 6.3.1. Hose rack HR96 is the most hydraulically remote hose connection with a license renewal intended function that is in an area

RBG-47818 Page 33 of 44 where water disposal can reasonably be accomplished . The degree of fouling in the piping that supplies HR96 is expected to be representative of the degree of fouling in the rest of the standpipe system including the piping that supplies the most hydraulically remote hose connection . The changes to LRA Sections A.1 .20 and B.1.20 follow with additions underlined and deletions lined through . A.1.20 Fire Water System The Fire Water System Program will be enhanced as follows .

Revise Fire Water System Program procedures to perform a full flow test on hose rack HR96, Control Building 135'0" elevation stairwell in accordance with Section 6.3.1 of NFPA 25 (2011 edition) .

B.1.20 Fire Water System Exceptions to NUREG-1801 The Fire Water System Program has the following exceptions. Element Affected Exception

4. Detection of Aging Effect NFPA 25, Section 6.3.1 specifies flow testing every five years at the hydraulically most remote hose connections of each zone of an automatic standpipe system to verify the water supply still provides the design pressure at the required flow. Because flow testing the hydraulically most remote hose connection is not practical, RBS will perform the testing at hose rack HR96, Control Building 135'0" elevation stairwell rather than the hydraulically most remote hose connection . RBS ~eFf:sFffis fiFe wateF

                                                ~I::lffi~ flsw testiA~ ts 'JeFify tl=le wateF 61::l~l3ly I3FsIJiEles fh", rI",.,.i,..,n nr",.,..,. ,r", .... nrl r",,..,, .ir",rI fir"., 2 Bases for Exceptions:

2. To flow test the hydraulically most remote hose connection of the automatic standpipe system in a manner that would provide sufficient information to verify design pressure and flow would generate a large quantity of liquid that is potentially radwaste and could create a risk of wetting components critical to normal and shut down operations. Managing this large quantity of water is not practical because of the difficulty of water disposal in the radiologically controlled area . An alternative of running hoses to an outside location from inside the auxiliary building would have a negative impact on secondary containment pressure boundary due to having to breach the boundary to route the hose to the outside.

By not performing additional flow testing , the potential for creating radwaste and increasing operational risk is reduced .

RBG-47818 Page 34 of 44 The materials of construction and internal environment for the automatic standpipe system are consistent. Therefore , the effects of aging that may result in flow blockage can be detected through testing in parts of the system that will not significantly increase the amount of radwaste or increase the potential operational risk. RBS flows the fire hoses listed in the Technical Requirements Manual (TRM) every three years per the TRM and

       '.vill perform main drain tests on 20 percent of the standpipes and risers each refueling outage. Acceptance criteria consist of ensuring an open flow path by verifying valve operability and flow through valve and connections with no indication of obstruction or undue restriction of water flow.

The following enhancements will be implemented prior to the period of extended operation . Element Affected Enhancement

4. Detection of Ag ing Effect

Revise Fire Water System Program procedures to perform a full flow test on hose rack HR96, Control Building 135'0" elevation stairwell in accordance with Section 6.3.1 of NFPA 25 (2011 edition) .

Question RAI B.1.20-2 (TRP 28 Fire Water System)

Background

LRA Section B.1.20, Enhancement No . 2 lists several deluge sprinkler systems for which the inspection procedures will be revised to conduct an internal visual inspection . LRA Section B.1.20, Enhancement No . 17 lists several pressure reducing valves for which the inspection procedures will be revised to inspect, test, and maintain the valves in accordance with NFPA 25 Section 6.3.1.4. Issue During the aud it, the staff confirmed that all of the deluge sprinkler systems listed in Enhancement No. 2 are addressed in the plant specific nozzle inspection procedure. However, this procedure also includes several other deluge sprinkler systems that are not included in the enhancement; for example, systems protecting components in the turbine , auxiliary control , and fire protection buildings. LRA Section 2.4.3 states that these buildings provide physical support, shelter, and protection for SSCs that have intended functions consistent with 10 CFR 54.4. The staff lacks sufficient information to conclude that the deluge sprinkler systems listed in Enhancement No. 2 include all those with intended functions within the scope of 10 CFR 54.4. The staff lacks sufficient information to confirm that the pressure reducing valves listed in Enhancement No. 17 include all those with intended functions with in the scope of 10 CFR 54.4. Reguest For the deluge sprinkler system :

1. State whether the list of deluge sprinkler systems cited in Enhancement No. 2 includes all deluge sprinkler systems with intended functions within the scope of 10 CFR 54.4.

2. If there are additional deluge sprinkler systems with intended functions within the scope of 10

RBG-47818 Page 35 of 44 CFR 54.4, what changes will be incorporated into Enhancement No. 2?

3. If there are additional deluge sprinkler systems with intended functions within the scope of 10 CFR 54.4 and they will not be included within the scope of Enhancement No. 2, state how loss of material and flow blockage will be managed for these deluge sprinkler systems.

For the pressure reducing valves :

4. State whether the list of pressure reducing valves cited in Enhancement No. 17 includes all the pressure reducing valves with intended functions within the scope of 10 CFR 54.4.

5. If there are additional pressure reducing valves within the scope of 10 CFR 54.4, what changes will be incorporated into Enhancement No. 17?

6. If there are additional pressure reducing valves with intended functions within the scope of 10 CFR 54.4 and they will not be included within the scope of Enhancement No. 17, state how flow blockage will be managed for these pressure reducing valves .

Response

1. NFPA 25 defines a deluge sprinkler system as employing open sprinklers that are attached to a piping system that is connected to a water supply through a valve that is opened by the operation of a detection system installed in the same areas as the sprinklers. Enhancement 2 covers the deluge sprinkler systems as defined in NFPA 25 with intended functions corresponding to 10 CFR 54.4(a)(3) that have dry pipe downstream of deluge valves . The remaining systems identified as deluge systems in the sprinkler header/nozzle inspection procedure either do not perform a license renewal intended function for 10 CFR 54.4(a)(3) or do not meet the definition of deluge system in NFPA 25.

2. As stated in the response to question 1. there are no other deluge sprinkler systems as defined in NFPA 25 with intended functions corresponding to 10 CFR 54.4(a)(3) that have dry pipe downstream of deluge valves . As such , no changes to Enhancement 2 are necessary.

3. Sprinkler systems for charcoal filter units are actuated by opening manual isolation valves.

Such systems are identified as deluge systems in the RBS procedure for sprinkler header/nozzle inspections. However, these systems don 't meet the NFPA 25 definition of deluge system and are not addressed by Enhancement 2. Enhancement 12 provides for an annual air flow test to check for obstruction in charcoal filter sprinkler systems that perform a license renewal intended function corresponding to 10 CFR 54.4(a)(3) .

4. In accordance with NFPA 25, a pressure-reducing valve is a valve designed for the purpose of reducing the downstream water pressure under both flowing (residual) and nonflowing (static) conditions . The list of pressure-reducing valves cited in Enhancement 17 includes pressure-reducing valves (pressure relief valves) with license renewal intended functions corresponding to 10 CFR 54.4 (a)(3) for the fire protection - water system . However, Enhancement 17 was intended to address provisions of NUREG-1801 ,

XI.M27 as modified by LR-ISG-2012-02 related to standpipes, sprinkler connections to standpipes, and hose stations, specifically the provisions of NFPA 25, Section 6.3.1.4. The valves identified in Enhancement 17 are not associated with standpipes, sprinkler connections or and hose stations. Therefore , Enhancement 17 is deleted as shown below.

RBG-47818 Page 36 of 44

5. There are no additional fire protection - water system pressure-reducing valves associated with standpipes , sprinkler connections to standpipes, or hose stations within the scope of 10 CFR 54. Therefore , Enhancement 17 can be deleted .

6. There are no additional fire protection - water system pressure-reducing valves associated with standpipes, sprinkler connections to standpipes, or hose stations within the scope of 10 CFR 54. Therefore, Enhancement 17 can be deleted .

The changes to LRA Sections A.1 .20 and 8.1 .20 follow with deletions lined through . A.1.20 Fire Water System The Fire Water System Program will be enhanced as follows .

Revise Fire 'Piater System Program prooedures to inspeot, test and maintain pressure_

reduoing_valves_FPW RV2A/B , FPW RV113 , and FPVV RV386jn aooordanoe with the requirements of Chapter 13 of ~JfPA 25 (Refer to NFPA 25 (2011 Edition) Seotion 6.3.1.4) . 8.1.20 Fire Water System Enhancements The following enhancements will be implemented prior to the period of extended operation . Element Affected Enhancement

4. Deteotion of Aging Effeot Re!~ise Fire Water System Program prooedures to inspeot, test and maintain pressureJeduoing _!~alves FPW R}J2NB , FPW RV11 3, and FP\lIi RV386jn aooordanoe !,'Iith the requirements of Chapter 13 of NFPA 25 (Refer to NFPA 25 (2011 Edition) Seotion 6.3.1.4).

Question RAI B.20-3 (TRP 28 Fire Water System)

Background

LRA Section B.1.20, Enhancement No. 13 states that the fire water system procedures will be revised to verify that fire hydrant barrels drain within 60 minutes after flushing or flow testing . GALL Report AMP XI .M27 , as modified by LR ISG 2012 02, recommends that NFPA 25 Section 7.3.2, "Hydrants," be met. NFPA Section 7.3.2 states that each hydrant shall be opened fully and water flowed until foreign material has cleared and that flow is maintained for at least one minute.

RBG-47818 Page 37 of 44 Issue An exception to meeting the AMP XI.M27, as modified by LR ISG 2012 02, recommendations in regard to NFPA 7.3.2 was not stated. As a result, the staff lacks sufficient information to complete its evaluation of the consistency of fire hydrant testing to AMP XI.M27, as modified by LR ISG 201202. The staff cannot complete its review of the Fire Water System program without reviewing the changes to LRA Section 8.1 .20 Enhancement No. 13. Request: State the basis for not meeting the recommendation to ensure that each hydrant has been opened fully and water flowed until foreign material has cleared and that flow is maintained for at least one minute. Alternatively, what changes will be incorporated into the enhancement(s) to the Fire Water System program to include these recommendations?

Response

Fire Water System Program procedures will be revised to test three of the four fire hydrants with license renewal intended functions (Le., FHY9, FHY10 and FHY11) by fully opening each for at least one minute and maintaining flow until foreign material has cleared. It is impractical to fully open fire hydrant FHY13. Managing the large volume of water released from the fully opened hydrant would require the deployment of approximately 100 feet of 2.5 inch hose in a congested, high-traffic area. However, FHY13 will be tested with the hydrant valve partially open until any foreign material has cleared. This approach is acceptable because plant underground fire protection system piping is 12" cement-lined piping, the RBS fire water system is supplied from well water, which is not expected to contain foreign material sufficient to affect system performance, and the flow from the hydrants has historically been clear of foreign material during testing. The changes to LRA Sections A.1.20 and 8 .1.20 follow with additions underlined. A.1.20 Fire Water System The Fire Water System Program will be enhanced as follows.

Revise Fire Water System Program procedures to test hydrants FHY9. FHY10 and FHY11 annually in accordance with Section 7.3.2 of NFPA 25 (2011 Edition) and test FHY13 with the hydrant valve partially open until any foreign material has cleared.

RBG-47818 Page 38 of 44 8.1.20 Fire Water System Enhancements The following enhancements will be implemented prior to the period of extended operation . Element Affected Enhancement

4. Detection of Aging Effect Revise Fire Water System Program Qrocedures to test hydrants FHY9, FHY10 and FHY11 annually in accordance with Section 7.3.2 of NFPA 25 (2011 Edition) and test FHY13 with the hydrant valve Qartially oQen until any foreign material has cleared.

Question RAI B.1.20-4 (TRP 28 Fire Water System)

Background

LRA Section B.1.20, Enhancement Nos. 6, 15, and 16 state that: (a) internal Fire Water Storage Tank (FWST) inspections will be conducted in accordance with NFPA 25 Sections 9.2.6 and 9.2.7; and (b) ultrasonic thickness measurements of the FWSTs will be conducted when there is evidence of pitting or corrosion . AMP XI.M27 , as modified by LR ISG 2012 02, states regardless of conditions observed on the internal surfaces of the tank, bottom-thickness measurements should be taken on each tank during the first 1O-year period of the period of extended operation . During the staff's review of plant specific documents the staff noted that there is an internal lip on the inside ring of the FWST foundation where water could accumulate through the thickness of sand . During the walkdown of the FWSTs the staff noted that: (a) there is an approximately 3/8 inch thick layer of grout installed at the tank to concrete interface; (b) the grout is missing in some locations; (c) at one location where the grout is missing, a fibrous material was detected approximately Y2 inch inside the tank bottom ring ; and (d) there is no caulking or sealant applied at the tank to concrete interface. Issue Neither Enhancement Nos . 6, 15, nor 16 are consistent with AMP XI.M27 , as modified by LR ISG 2012 02, in that wall thickness measurements will only occur if there is evidence of corrosion . As a result of the potential for water to accumulate in the sand under the tank, the degraded condition of the grout, and lack of caulking or sealant at the tank to concrete interface, the staff has determined that loss of material due to general, pitting and crevice corrosion could be occurring on the tank bottom . AMP XI.M27 does not include any recommendations for the quantity of data points or location of the bottom thickness measurements. However, given the

RBG-47818 Page 39 of 44 potential for loss of material on the external surfaces of the bottom of the tank, the staff requires this information to complete its evaluation of the effectiveness of the Fire Water System program . GALL Report AMP XI.M27, as modified by LR ISG 2012 02, Table 4a , "Fire Water System Inspection and Testing Recommendations ," recommends a one-time inspection for the FWSTs. The staff recognizes that the one time inspections might not reveal any loss of material that could challenge the ability of the FWSTs to meet their intended functions throughout the period of extended operation . However, given the potential for loss of material to occur on the bottom external surface of the tanks , the staff needs to review the criteria that would be used to conclude that one time in lieu of periodic FWST bottom thickness measurements would be conducted . The staff cannot complete its review of the Fire Water System program without reviewing the changes to LRA Section B.1.20 necessary to address potential enhancements to the program associated with bottom thickness measurements. Request

1. State the basis for not conducting tank bottom thickness measurements if there is lack of evidence of internal tank corrosion. Alternatively, what enhancements to the Fire Water System program associated with tank bottom thickness measurements being conducted regardless of the lack of evidence of internal tank corrosion will be incorporated into the program?

2. State: (a) the quantity and location of data points for the bottom thickness measurements; and (b) associated enhancement changes. In addition , state the basis for why the quantity and location of data points will be sufficient to detect loss of material due to general , pitting ,

or crevice corrosion .

3. State what acceptance criteria will be used to conclude that a one time bottom thickness measurement of each FWST is adequate in lieu of periodic inspections? In addition , what changes will be incorporated in the associated enhancements?

Response

1. The Fire Water System Program is enhanced to conduct a volumetric examination prior to the period of extended operation (PEO) and a second volumetric examination during the first 10-year period of the PEO to detect loss of material from the external surface of the bottoms of the fire water storage tanks .

2. Each fire water storage tank will be inspected and recoated prior to the period of extended operation. Tank bottom inspections will consist of a low-frequency electromagnetic test (LFET) scan , or equivalent, with UT examinations where there is indication of potential thinning . In the event LFET scan does not provide reliable information , the inspections will consist of at least 25 UT thickness measurements of the tank floor (at least four UT readings in each quadrant, at least three of which are within six inches of the outer circumference) .

The inspections performed near the outer wall of the tanks will constitute approximately 50% of the total number of inspections providing a focus on the areas immediately above the concrete ring foundations where detrimental effects from water intrusion are more likely. NUREG-1801 specifies 25 inspections as a representative sample in a number of programs, for example, the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program described in NUREG-1801 , Section XI.M38 . The LFET or UT examinations performed prior to the PEO will allow assessment of the condition (i.e. , loss of material due to corrosion) of the tank bottom external surface and establish reference data for

RBG-47818 Page 40 of 44 comparison to data from LFET or UT examinations during the PEa to determine a rate of degradation . The Fire Water System Program is revised to include an inspection within 8 years prior to the PEa and a subsequent inspection during the first 1O-year period of the PEa.

3. An enhancement to the Fire Protection Program provides for volumetric examination of the tank bottoms both prior to and during the PEa. Data from these examinations will be used to assess the condition of the external surface of the bottom of the tank, and to determine if and when additional tank bottom thickness measurements should be taken . The timing of future inspections, if any, will be based on the estimated time for bottom plate thickness to approach the minimum requ ired thickness using corrosion rates determined from the examination data.

The changes to LRA Sections A.1 .20 and B.1.20 follow with additions underlined . A.1.20 Fire Water System The Fire Water System Program will be enhanced as follows .

Revise Fire Water System Program Qrocedures to conduct examinations of the fire water storage tank floors . The first examination shall be Qerformed Qrior to the Qeriod of extended oQeration (PEa) following removal of the existing coating and the subseguent examination will be Qerformed during the first 10 years of the PEa. The examinations shall consist of a low-freguency electromagnetic test (LFET) scan , or eguivalent, and ultrasonic testing (UT) where there is indication of Qotential thinning of the floor Qlates. In the event the LFET scan , or eguivalent, does not Qrovide reliable information , 25 UT thickness measurements shall be Qerformed of the tank floor (at least four measurements in each guadrant, at least three of which will examine the area within six inches of where the wall meets the floor) .

8.1.20 Fire Water System The following enhancements will be implemented prior to the period of extended operation . Element Affected Enhancement

4. Detection of Aging Effect Revise Fire Water System Program Qrocedures to conduct examinations of the fire water storage tank floors . The first examination shall be Qerformed Qrior to the Qeriod of extended oQeration (PEa) following removal of the existing coating and the subseguent examination will be Qerformed during the first 10 years of the PEa. The examinations shall consist of a low-freguency electromagnetic test (LFET) scan ,

or eguivalent, and ultrasonic testing (UT) where there is indication of Qotential thinning of the floor Qlates. In the event the LFET scan, or eguivalent, does not Qrovide reliable information, 25 UT thickness measurements shall be Qerformed of the tank floor (at least four measurements in each quadrant at least three of which will examine the

RBG-47818 Page 41 of 44 Question RAI B.20-5 (TRP 28 Fire Water System)

Background

LRA Section B.1.20, Enhancement No. 19 states an acceptance criterion that, "[c]oating meets the plant-specific design requirements for the coating/lining and substrate for the fire water tanks ." GALL Report AMP XI.M42 states that , U[a]dhesion testing results , when conducted , meet or exceed the degree of adhesion recommended in plant-specific design requirements specific to the coating/lining and substrate." Issue It is not clear to the staff that the acceptance criterion in Enhancement No. 19 is applicable to adhesion testing . It is possible that the acceptance criterion could be interpreted to only apply to coating characteristics such as material type and dry film thickness . The staff cannot complete its review of the Fire Water System program without reviewing the changes to Enhancement No . 19. Reguest Clarify the intent of the above cited acceptance criterion and what changes will be incorporated into Enhancement No. 19.

Response

The intent of Enhancement 19 is to include adhesion testing acceptance criteria for the degree of adhesion recommended in plant-specific design requirements specific to the coating/lining and substrate. The changes to LRA Sections A.1.20 and B.1.20 follow with additions underlined and deletions lined through . A.1.20 Fire Water System The Fire Water System Program will be enhanced as follows .

Revise Fire Water System Program procedures to include the following acceptance criteria for the fire water tanks' interior coating :

         ~   Indications of peeling and delamination are not acceptable.
         ~   Blisters are evaluated by a coatings specialist qualified in accordance with an ASTM International standard endorsed in RG 1.54 including limitations, if any, identified in RG 1.54 associated with use of a particular standard. Blisters should be limited to a few intact small blisters that are not growing in number or size, and are completely surrounded by sound coating/lining bonded to the substrate. Blister size and frequency should not be increasing between inspections (e.g., reference ASTM 0714-02, "Standard Test Method for Evaluating Degree of Blistering of Paints") .

RBG-47818 Page 42 of 44

       ~  Indications such as cracking , flaking , and rusting are evaluated by a coatings specialist qualified in accordance with an ASTM International standard endorsed in RG 1.54 including limitations, if any, identified in RG 1.54 associated with use of a particular standard.
       ~  As applicable, wall thickness measurements, projected to the next inspection , meet design minimum wall requirements .
       ~  Coating meets the plant-specific design requirements for the coating/lining and substrate, including the reguired degree of adhesion when performing adhesion testingfor the fire water tanks .

B.1.20 Fire Water System Enhancements The following enhancements will be implemented prior to the period of extended operation . Element Affected Enhancement Revise Fire Water System Program procedures to

6. Acceptance Criteria include the following acceptance criteria for the fire water tanks' interior coating :

Indications of peeling and delamination are not acceptable.
Blisters are evaluated by a coatings specialist qualified in accordance with an ASTM International standard endorsed in RG 1.54 including limitations, if any, identified in RG 1.54 associated with use of a particular standard .

Blisters should be limited to a few intact small blisters that are not growing in number or size, and are completely surrounded by sound coating/lining bonded to the substrate. Blister size and frequency should not be increasing between inspections (e.g., reference ASTM 0714-02 , "Standard Test Method for Evaluating Degree of Blistering of Paints") .

Indications such as cracking , flaking , and rusting are evaluated by a coatings specialist qualified in accordance with an ASTM International standard endorsed in RG 1.54 including limitations, if any, identified in RG 1.54 associated with use of a particular standard .
As applicable, wall thickness measurements, projected to the next inspection , meet design minimum wall requirements .
Coating meets the plant-specific design requirements for the coating/lining and substrate, includina the reauired deqree of adhesion when

RBG-47818 Page 43 of 44 performing adhesion testingfor the fire water taAAs. Question RAI B.1.20-6 (TRP 28 Fire Water System)

Background

During the audit, the staff reviewed the Fire Water Storage Tank (FWST) internal inspection results from 2011 , which stated that no significant degradation was noted and the internal protective coating is in good condition . Internal inspections in 2016 revealed significant coating blistering on the tank bottom . Condition reports were appropriately initiated for the inspection results . The "acceptance criteria" program element of AMP XI.M42 states , "[b]listers should be limited to a few intact small blisters that are completely surrounded by sound coating/lining bonded to the substrate . Blister size and frequency should not be increasing between inspections ... " The "detection of aging effects" program element of AMP XI.M42 states that , "[b]aseline coating/lining inspections occur in the 1O-year period prior to the period of extended operation." The "corrective actions" program element of AMP XI.M42 states that , "[c]oatings/linings that do not meet acceptance criteria are repaired , replaced , or removed ." Issue Based on the staff's review of pictures attached to the inspection results for the 2016 internal visual inspection of the FWSTs, the coatings do not meet the acceptance criterion (for entry into the period of extended operation) that blisters are limited to a few intact small blisters. The 2016 inspections could satisfy the AMP XI.M42 recommendation to conduct a baseline inspection 10 years prior to the period of extended operation . As a result, the staff lacks sufficient information to conclude that the corrective actions associated with the 2016 inspection results or any other inspections conducted prior to the period of extended operation will be consistent with the "corrective actions" program element of AMP XI.M42 . Lacking consistency with the "corrective actions" program element or a cited exception to the recommendations accompanied by an adequate basis, the staff lacks a basis to establish reasonable assurance that the FWSTs will meet their intended function during the period of extended operation. During the audit, it was stated that the reason the blistering was not detected during the 2011 inspections was that the tank was not completely drained . During the staff's review of the internal inspection procedures for the FWST, it was noted that there is not a step requiring complete draining of the tank . The staff lacks sufficient information to conclude that the FWST internal inspections will be adequate unless the tank is completely drained . Request

1. State the corrective actions that will be taken for the internal coating blistering in the FWSTs based on the 2016 inspection results or any other inspections conducted prior to the period of

RBG-47818 Page 44 of 44 extended operation .

2. State that basis for why the inspections will be adequate if the tanks are not completely drained or state the changes to the Fire Water System prog ram to require complete draining of the FWST tanks during the conduct of internal inspections .

Response

The corrective actions that will be taken prior to the period of extended operation (PEO) in response to the results of the 2016 inspection of the fire water storage tanks (FWSTs) include the following .

The existing coating will be removed and bottom thickness measurements will be taken as described in the response to RAI B.1.20-4.
The fire water storage tanks will be recoated .

1. The Fire Water Program procedures will be revised to perform the internal inspections with the tank completely drained .

The changes to LRA Sections A.1 .20 and 8.1 .20 follow with add itions underlined . A.1.20 Fire Water System The Fire Water System Program will be enhanced as follows .

Revise Fire Water System Program procedures to inspect the interior of the fire water tanks in accordance with NFPA 25 (2011 Edition) , Sections 9.2.6 and 9.2.7, including sub-steps, using the guidance of SSPC-SP2, Hand Tool Cleaning ; SSPC-SP3, Power Tool Clean ing ; SSPC-SP11 , Cleaning of Bare Metal ; and SSPC-SP WJ-1, 2, 3 and 4, Water Jet Cleaning . Perform the interior inspection with the tank completely drained.

A.4 LICENSE RENEWAL COMMITMENT LIST No. Program or Commitment Implementation Source Activity Schedule (Letter Number) 12a Fire Water Remove existing coating , Within seven years RGB-478 18 System perform bottom thickness prior to February measurements and recoat the 28, 2025. fire water storaqe tanks . 8.1.20 Fire Water System The following enhancements will be implemented prior to the period of extended operation . Element Affected Enhancement

4. Detection of Aging Effect Revise Fire Water System Program procedures to inspect the interior of the fire water tanks in accordance with NFPA 25 (2011 Edition) , Sections

RBG-47818 Page 45 of 44 9.2 .6 and 9.2.7, including substeps, using the guidance of SSPC-SP2, Hand Tool Cleaning ; SSPC-SP3, Power Tool Cleaning ; SSPC-SP11 , Cleaning of Bare Metal ; and SSPC-SP WJ-1, 2, 3 and 4, Water Jet Cleaning . Perform the interior inspection with the tank completely drained.

RBG-47818 Set 7 Commitment

RBG-47818 Page 1 of 1 This table identifies actions discussed in th is letter that Entergy comm its to perform . Any other actions discussed in this submittal are described for the NRC's information and are not commitments . TYPE SCHEDULED (Check one) COMMITMENT COMPLETION DATE ONE-TIME CONTINUING (If Required) ACTION COMPLIANCE 12a. Fire Water System Remove existing Within seven years coating , Qerform bottom thickness Qrior to February measurements and recoat the fire water X 28, 2025. storaqe tanks .

RBG-47818 Enclosure 3 Responses to Request for Additional Information Set 7 Non-Proprietary Information (16 pages)

_ HITACHI GE Hitachi Nuclear Energy 003N4606-NP Revision 2 January 2018 Non -Proprietary Information - lass I (Public) River Bend Station Unit 1 Main Steam Line Flow Restrictors RBS License Renewal (LR) Time-Limited Aging Analysis (TLAA) Support Copyright 20 18, GE-Hitachi Nuclear Energy Americas LLC All Rights Reserved

003N4606-NP Revision 2 Non-Proprietary Information - Class I (Public) INFORMATION NOTICE This is a non-proprietary ver ion of the document 003N4606-P Revision 2, which has the proprietary information removed. Portions of the document that have been removed are indicated by an open and closed bracket as shown here [[ ]]. IMPORTANT NOTICE REGARDING CONTENTS OF THIS REPORT Please Read Carefully The design, engineering, and other information contained in this document are furnished for the purpose of supporting the Entergy license amendment request for a license renewal at River Bend Station in proceedings before the U.S. Nuclear Regulatory Commission. The only undertakings of G H with respect to information in this document are contained in the contracts between GEH and its customers or participating utilities, and nothing contained in this document shall be construed as changing the contract. The use of this information by anyone other than Entergy, or for any purpose other than that for which it is furnished by GEH is not authorized ; and with respect to any unauthorized use, GEH makes no representation or warranty, express or implied, and assumes no liability as to the completeness, accuracy, or usefulness of the information contained in this document, or that its use may not infringe privately owned rights. 11

003N4606-NP Revision 2 Non-Proprietary Information - Class I (Public) REVISION

SUMMARY

Revision Revision Description 0 Initial release for Customer Comment I Updated document to incorporate re olution to ustomer comment 2 Revised to mark specific instances ofGEH proprietary information III

003N4606-NP Revision 2 Non-Proprietary Information - Class I (Public) TABLE OF CONTENTS

1.0 INTRODUCTION

.............................................................. .......... ......................................... 1

1. 1 PURPOSE ............................................... ....... ... ..... ..... ... ................ ... .............. ........... ......... .... . 1 1.2 SCOPE ..... ... ... .. ... ... .... ... .. .................................................................. ................................. ..... . 1 2.0

SUMMARY

...... ...................... ..................................................... ............................. ............ 2 3.0 EVALUATION ....................... ........................................... ........................... .... .... ..... .. ......... 3

3. 1 ASTING MATERIAL EVALUATION ..... .. ... .... .......... ............ .......... ............... .......... ......... 3

3. I. I Material Loss Rate Assessment.. ...... ............. ...... ...... ... ......... ..... ........... ..... ........ ...... 5 3.1.2 FAC Asse ment .... ........... .. ................................. ............. ................................... ... . 5

3. 1.3 rosion A e sment ......... ..... ......... ........ ... ... .................. ... ... .... ..... ...... ...................... 5 3.1.4 Corrosion Assessment .......... ......... ......... ...... .......... .................................................. 8

3. 1.5 Material Loss Rate Summary .. ........................ ... ............... ....................................... 9 3.2 INCREASE IN STEAM RELEASE AND IMPA T TO OFFSITE DOSE .................... .... .... 9 3.3 INSPECTION FREQUENCY ........ ..... ... ...... .......................................................... ... .... ...... .. 10

4.0 REFERENCES

........................... ......... ........... ....... .......... ... ..... .......... ....... ...... ..................... 11 lV

003N4606-NP Revision 2 Non-Proprietary Information - Class I (Public) LIST OF TABLES Table 3-1 : Grade CF8 Chemistry per ASTM A351 .... .. ......... .. .... .. ......................... ........... ..... ........ 3 Table 3-2: CASS Thermal Aging Susceptibility Screening Criteria .... .......... .. .. ........ ................... .4 Tab le 3-3: Corrosion Data for Carbon and Stainless Steel .............. ..... ... ...... .... .... .... ....... .... ... ... ....8 Tab le 3-4: Choked Flow Results Summary .. .. ... ... .... .. .. ... .. .. ...... ... .......................................... .... .. ..9 LIST OF FIGURES Figure 3-1: Effect of Cr and Temperature (Reference 15) .. .. ..... .. .. ... .. .. ..... ..... ...... ................... ...... 6 Figure 3-2: Flow Velocity Dependence (Reference 15) .. ....... ....... ..... ... ..... .. .. .... ... .... ... ...... ............ 7 v

003N4606-NP Revision 2 Non-Proprietary Information - Class I (Public)

1.0 INTRODUCTION

1.1 PURPOSE In support of River Bend Station Unit 1 (RB ) li cense renewal , the main steam line flow restrictors were identified as having potential aging effects. There are four main steam lines coming off the top of the reactor vessel. Each steam line has a flow re trictor fabricated from two parts - an upstream cast stainless steel section that restricts flow and a downstream cast carbon steel portion . The specific concerns associated with the main steam line flow re trictors are the potential for thermal embrittlement of the casting and potential erosion resulting in an increase in choked flow. To address the embrittlement concern, GE Hitachi Nuclear Energy (GEH) researched the original purchasing and material specifications to determine the casting method and ferrite content for the main team line flow restrictor. The relative increase in team release due to erosion and other potential loss of material mechanisms of the restrictors wa assessed for 54 effective full power year (EFPY) of operation. The increase in flow due to material loss of the main steam line flow re trictor and its impact on offsite dose consequences was evaluated. The off: ite do e con equence were qualitatively assessed due to the potential increase in main steam line steam release . The evaluation also considered the need for inspections to address the applicab le aging effects. 1.2 SCOPE The main steam line flow re trictors have components that are fabricated from American Society for Testing and Material (A TM) A351 (Grade CF8) cast stainless steel and exposed to temperatures greater than 482°F. G H researched the original purchase and material specifications to determine the material type, ca ting method, and ferrite content (if applicable) for the upstream component of the main steam flow restrictors to determine if they are subject to thermal aging embrittlement. GEH also determined whether the increase in main steam flow due to material loss of the main steam flow restrictors is acceptable through 54 EFPY of operation.

003N4606-NP Revision 2 Non-Proprietary Information - Class I (Public) 2.0

SUMMARY

GEH evaluated the main steam line flow restrictors for potential thermal aging embrittlement and the impact on the main steam flow due to materia l loss of the main steam flow restrictors through 54 FPY of operation.

The cast austenitic stainless steel upstream castings have a ferrite content ranging from 15% to 27% ferrite based on Hull 's equivalent factors for calculating delta ferrite and are centrifugally cast.
The downstream castings are centrifugally cast carbon steel.
A reduction of the material loss rate from 0.004 inches per year to [[

             ]] for the upstream castings is acceptable for design calculations.

The choked flow is [[ ]] after 54 EFPY when a [[

              ]] material loss rate is taken into account.

The radiological dose release increase matches the ll1crease choked flow increase at

[[ ]].

No additional inspections of the mall1 steam line flow restrictors are recommended relative to the :

o Increase in steam release o Offsite dose considerations o Thermal aging concerns Thi verified information may be used to support the licen e renewal of RBS . 2

003N4606-NP Revision 2 Non-Proprietary Information - C lass 1 (Public) 3.0 EVALUATION The casting material , increase in steam release, impact to offsite dose, and inspection frequency are evaluated as follows. 3.1 CASTING MATERIAL EVALUATION Review of the main steam line master parts li st for RBS indicates that the main steam line flow restrictor 105D5425 GOOI (Reference 1) was used for RBS . Each flow restrictor was assembled from an upstream casting 105D5082P004 (Reference 2) and a downstream casting 105D5083P003 (Reference 3). The flow restrictor (venturi) throat that contro ls choked flow rate is part of the upstream casting. The downstream casting does not impact the choked flow calculations. Therefore, an evaluation of the material loss rate was performed for the upstream casting material to provide input to the updated choked flow calculations. Upstream Casting The upstream casting drawing specifies material per GEH specification B50YP43-Al (Reference 4). The B50YP43 materials specification requires the casting material to be ASTM A351 Grade CF8 material. Suffix Al requires that the material be solution heat treated . GEH added the following chemical and microstructural requirements to the base specification requirements:

The chemistry of the casting shall be controlled within the allowable limits to produce a casting with a minimum of 8% ferrite as determined from the chemical analysis in accordance with the Shaeffler or choefer diagrams.
The sum total of Co lumbium (Niobium), Tantalum, and Titanium shall not exceed 0.1 %.

The chemistry requirements of Grade CF8 material as defined in ASTM A351 are given in Table 3-1 below. Table 3-1: Grade CF8 Chemi try per ASTM A351 Element Cr Mn Si S P C Ni Mo Weight % (max unless 18.0 to 2 1.0 1.50 2.00 0.040 0.040 0.008 8.0 to 11.0 0.50 range is given) The Product Quality Certification certified that the four main steam flow restrictors for RBS conformed to the applicable codes, standards, and pecifications. Review of the available materials test reports for the upstream castings shows that the upstream castings were produced by Wisconsin Centrifugal, indicating that the components were centrifugally cast. The materials test reports of the three out of four castings contain the ferrite levels (13%, 16.5%, and 19.5%) of the material supp lied to RB per the Schaeffler diagram, which satisfies the requirements of the specification. The available records for the upstream castings indicate that there were 35 components provided by Wisconsin Centrifugal to GEH and no other vendors were used. Based on this, the remaining casting was supplied by Wisconsin Centrifugal, and therefore was 3

003N4606-NP Revision 2 Non-Proprietary Information - Class 1 (Pub lic) also centrifugally cast. Review of the available records of all the upstream castings indicates the expected chemistry would result in a ferrite content of approximately 17% and a reasonable upper bound (+2<J) for the potential ferrite content would be approximately 27% based on a statistical assessment of the 35 available component chemistries based on Hull's equivalent factors for calculating delta ferrite as discu ed in NUREG-4513 (Reference 5). Per Reference 6, Nuclear Regulatory Commission (NRC)-sponsored research at Argonne National Laboratory (ANL) has shown that aging of Cast Austenitic Stainless Steel (CASS) at reactor operating temperatures of280-350°C (536-662°F) can lead to changes in their mechanical properties. To determine the susceptibility of CASS components to thermal aging, the NRC recommends using a screening method based upon the molybdenum content casting method, and ferrite content, as summarized in Table 3-2. Note in the susceptibility screening method , ferrite content is calculated by using the Hull ' s equivalent factors or a staff-approved method for calculating delta ferrite in CAS materials. Table 3-2: CASS Thermal Aging Susceptibility Screening C r iteria Molybdenum Content usceptibility Ca ting Method Ferr ite Level (Wt%) Determination

                                                             < 14%                  Not susceptible Static High                                             > 14%               Potentially susceptible (2 .0 - 3.0)
                                                             < 20%                  Not susceptible Centrifuga l
                                                             > 20%               Potentially susceptible
                                                             < 20%                  Not sllsceptible Low                      tatic (0.50 max)                                           > 20%               Potentially susceptible Centrifugal                    All                 Not susceptible The upstream casting is composed of A TM A351 Grade CF8 material with low molybdenum content (SO.50% Mo) . The available records indicate that centrifugal casting was the manufacturing method for the main steam line flow restrictors. Therefore, the upstream castings of the main steam line flow restrictors are not considered susceptible to thermal aging concerns because Mo is S 0.50% and the component is centrifugally cast.

Downstream Castings The downstream castings have the following GEH material specification options: B50YPl17-A3A (Reference 7), B50YP28-A2A (Reference 8), or B50YP68-A3 (Reference 9). Review of the Materials Test Reports for the downstream castings show that B50YPl17-A3A material was used to procure the RBS downstream castings. The B50YPl17 materials specification invokes ASME SA-216 grade WCB material per suffix A3A, which is a carbon steel casting. Suffix A3A requires that the material be impact tested at maximum temperature of 60°F as well as radiographically and liquid penetrant examined. The Material Test Reports for the downstream castings were also produced by Wisconsin Centrifugal, indicating that the components were centrifugally cast. Because the downstream castings are carbon steel, they are not susceptible to thermal aging at these temperatures. 4

003N4606-NP Revision 2 Non-Proprietary Information - Class I (Public) 3.1.1 Material Loss Rate Assessment Erosion-corrosion is a co-joint activity involving corrosion and erosion in the presence of a moving corrosive fluid , leading to the accelerated loss of material as defined by Reference 10. Erosion-corrosion encompasses a wide range of flow-induced corrosion processes. Flowing fluids can damage protective films on metals resulting in greatly accelerated corrosion. Damage to the films may be the result of mechanical forces or flow-enhanced dissolution and the accelerated corrosion may be accompanied by erosion of the underlying metal. Reference 11 states, "Flow-accelerated corrosion (F AC) is sometimes referred to as flow-assisted corrosion or incorrectly as erosion-corrosion. F AC leads to wall thinning (metal loss) of carbon steel piping exposed to flowing water or wet steam. The rate of metal loss depends on a complex interplay of many parameters including component geometry , water chemistry, material composition, and hydrodynamics" . Reference 12 updates the definition in Reference 13 to state "Flow-accelerated corrosion is a corrosion mechanism which results in wall thinning of carbon steel components exposed to moving, high temperature, low-oxygen water, such as Pressurized Water Reactor (PWR) primary and secondary water, and Boiling Water Reactor (BWR) reactor coolant. FAC is the result of dissolution of the surface film of the steel which is transported away from the site of dissolution by the movement of water. " In addition, Reference 12 also provides an update to the definition of erosion stating, "Erosion is the progressive loss of material due to the mechanical interaction between a surface and a moving fluid . Different forms of erosion include cavitation, flashing, droplet impingement, and solid particle impingement." The following addresses the impact of F AC, erosion, and corrosion on the main steam I ine flow restrictors. 3.1.2 F AC Assessment Not all systems are susceptible to F AC. Per Reference 11 , systems or portions of systems made of stainless-steel piping or low-alloy steel piping with nominal chromium content equal to or greater than 1.25% (high content ofFAC-resistant alloy) are not susceptible to FAC. In addition, the main steam line is expected to have sufficient dissolved oxygen content and low moisture content which further reduces the susceptibility to F AC for the main steam line flow restrictors. 3.1.3 Erosion Assessment Single phase steam flow is expected to have minimal impact on the passive layer found in stainless steels as stated in Reference 10. A two-phase flow condition is the primary concern for erosion because it is more damaging to the oxide layer due to the liquid droplets in the steam flow impinging on the surface, according to Reference 14. As stated in Reference 10, the attack involves exposure of the solid to repeated discrete impacts by liquid droplets, which generate impulsive and destructive contact pressures, far higher than those produced by steady flows. Impingement erosion has been an issue with low-pressure steam turbine blades operating in wet steam environments and also with rain erosion of aircraft and helicopter rotors. Higher chromium containing metals are often used in these environments. In the case of very high turbine blade velocities noted in Reference 14, chromium steels containing 12% chromium or less can suffer from other effects. Specifically, mechanical damage by cavitation occurs as opposed to material dissolution associated with erosion. Erosion issues observed in steam 5

003N4606-NP Revision 2 Non-Proprietary Information - Class I (Public) turbines involve wet steam with higher moisture content than the [[ ]] that is expected in the main steam line flow restrictors, and conditions conducive to cavitation are not expected in the main steam line flow restrictors. Control of liquid droplet impingement attack on components is controlled by design and material selection. Design aspects of control optimize the flow system geometry to reduce the amount of impacting liquid, angle of impact, and droplet size per Reference 10. The gradual reduction in the main steam line flow restrictor diameter minimizes the angle of impact possible on the narrowest section of the element. This reduces the effect of erosion on the minimum diameter in the upstream casting. According to Reference 10, increasing the temperature above the dew point can also mitigate liquid droplet impingement. The main steam line flow restrictors operate at elevated temperature (- 549°F), which aids in the reduction of liquid droplet impingement attack by inhibiting condensation of additional droplets that can impinge on the surface. The use of stainless steels has proven effective at mitigating liquid droplet impingement attack in annular mist flow on oil/gas production systems. However, caution should be exercised if austenitic stainless steel is exposed to low flow conditions in chloride environments as pitting can occur under deposits, as noted in Reference 10. In the case of the main steam line flow restrictors, chloride intrusion is not expected. Therefore, the potential for pitting associated with chloride ions is minimized in the Grade CF8 stain less steel in the upstream casting. It is demonstrated in Figure 3-1 , excerpted from Reference 15, that 18Cr stainless steels have negligible wear rates, provided the oxygen is present (- 0.100 ppm [100 /lg/kg] or higher). While the data shows a more basic water chemistry (pH of 9.5) inhibits erosion and corrosion, the

                                              ...---

neutral pH 7 value would be representative of reactor coolant. Additionally the erosion and corrosion rate begins to decrease above - 302°F (- 150°C) as shown in Figure 3-1 .

                                                                                   ~r-------------------------~

carbon sl 12 ~-- 1000 Carbon sleel2 + 500l1m tco 33

Carbon sleel- ::l 100

     + 500 11m nickel pH  0 , conteo1            Q) 1BCr Sl In! ss steet                     _     7   500~                  ~

_ 95 ,S IJQiI<g iii 30 13CI stainless steel _ 1 <5 ~ ~ ASTM d ealgnallon. ~ 10 2',Cr-1MosteeP 'A1G I Grll $

                                                ' A41 4  B                     ~      3 l Cr*v,Mo sl     *                         'A2 13   l22                   u
                                                'A213 Gr l12                  'E Cr*McrNI*V 5t     I
                                                                              ~       1 N,*Cr*   *V steel NI-Cu-McrNb sleel 0 1 o 10       50                 150         200                 122  2 12     302         2      482 Sp ItlC mal' lIal wear r I Il oIcml*hr                                  Temper lure F

3. Wear rate of various materia ls from erosion/corro- 4. Temperature effect on erosion/corrosion Is great-sion In 356F water at 580 pslg moving at 65.6 ft/sec est In 266-366F range. Data are for neutral 580-pslg Is shown for three typical pH/ oxygen combinations water w ith an oxygen content of less than 40 ~ g/kg fl owing at 11 5 n/sec. Exposure lime Is 200 hr Figure 3-1: Effect ofCr and Temperature (Reference 15) 6

003N4606-NP Revision 2 Non-Proprietary Information - Class I (Public) Figure 3-2 demonstrates that the flow velocity dependence of the wear rate decreases as the chromium content increases from none to 2.25% chromium. Therefore, it is expected to continue for higher chromium levels up to 12% chromium, where passivation can be achieved in the material. 5000

                             ....
                            .c N

Q E 1000 0)500

t.

ai

                             ~
                             .... 100 co
                             ~ 50
                            ~
                             ~
                             ~ 10 u

tI: 5 2V.Cr-Mo (A213 Gr T22)

.~

c% 1 0.5 I I I 32 .8 65 .6 98.4 131 .2 Flow velocity, fVsec

5. Flowing water increases mate-rial loss rate exponentially wi th flow velocity. Data are for neutral 580-psig/356F water with an oxy-gen content of less than 5 IJg/ kg.

Exposure time is 200 hr (above) Figure 3-2: Flow Velocity Dependence (Reference 15) In add ition to the chemical composition of the material, the operating conditions in the main steam line (flow rate, oxygen, and temperature) can have a significant effect on the potential for FAC, erosion, and corrosion. The main stean1 line conditions, and associated potential for FAC, were evaluated previously for a prototypical Advanced Boiling Water Reactor (ABWR) . The material evaluated in the ABWR analysis was ASTM A 106 Grade C, which is a carbon steel with a maximum chromium content of 0.4%. The temperature of the ABWR analysis is 550°F steam with an operating pressure of 1,025 psi. In addition, the oxygen concentration expected in the main steam line at RBS is on the order of [[ ]], which indicates that the ABWR analysis can be used to evaluate the potential for erosion and corrosion of the RBS main steam line flow restrictors. The result of the analy is indicates that [[ .

                                                                                                ]] in the evaluated ABWR plant. The upstream castings ' Grade CF8 material will have improved erosion performance relative to the ASTM A 106 Grade C material simu lated in the ABWR analysis because of the higher chromium content in the Grade CF8 material.

7

003N4606-NP Revision 2 No n-Proprietary Informatio n - Class I (Public) 3.1.4 Corrosion Assessment The use of stainless steel is recorrunended where high flow rates result in excessive ly high corrosion rates for carbon or alloy steel. Per Reference 14, the most important chemical constituent in carbon steels that are exposed to a water/steam environment (up to 300°C) is the amount of chromium. Typically, a cJu-omium content of 12% is sufficient to create a passive chromium oxide layer that prevents further corrosion of stainless steels in water/steam environments. Therefore, the 18% minimum chromium in Grade CF8 is more than sufficient to generate the passive chromium oxide layer for corrosion protection. Table 3-3 shows corrosion data for carbon and stainless stee l from various sources. Table 3-3: Corrosion Data for Carbon and Stainless Steel 40 Year Oxygen Flow Corrosion Material Temperature Corrosion Environment Level Velocity (inches per Reference Type (OF) Allowance (ppm) (fps) year) (inches) GEH [[ internal data Carbon Steel GEH

                                                                                           ]]     internal data team          up to 475        -       -         0.08*       0.002*           16 GEH

internal data 300 Series GEH Stainless internal teel data Steam up to 475 - - 0.08* 0.002* 16 Water 550 - 200 0.04 0.001 17 Notes: - represents conditions not reported

represents values that were reported as less than This indicates that 300 serie austenitic stainless steels, which have a similar composition to Grade CF8 material , have significantly lower corrosion rates when compared to carbon steels in water and steam environments.

8

003N4606-NP Revision 2 Non-Proprietary Information - Class I (Pub lic) 3.1.5 Material Loss Rate Summary The historic material loss rate of 0.004 inches per year from F AC, erosion, and corrosion for the main steam line flow restrictors ' upstream casting is conservative based on the following:

The use of high chromium material (Grade CF8) provides resistance to loss of material and reduces the dependence of material loss rate on flow velocity for the upstream casting in the main steam line flow restrictors.
The case where 12% Cr steels have shown erosion damage have involved higher moisture content fluids than the [[ ]] liquid present in the main steam flow.
The gradual reduction in diameter minimizes the angle of impact on the narrowest section of the element red ucing the effect of erosion within the region containing the minimum diameter.
The erosion and corrosion rate for stee ls begins to reduce at temperatures above approximately 302°F and is dramatically reduced in the presence of oxygen (over approximately 0.100 ppm).
Evaluation of an ABWR main steam line e lbow concluded that [[

                                                         ]] in the carbon steel components that are more susceptible to eros ion or corrosion than components made from Grade CF8 material.

As shown in Table 3-3 , for carbon stee l (at a flow velocity of [[ ]] and

[[ ]]) the corrosion rate is bounded by [[ ]). Based on the above points and the significant improvement in the performance of Grade CF8 relative to carbon steel, a reduction of the material loss rate from [[

                      ]] for the upstream casting is acceptable for design calculations.

3.2 INCREASE IN STEAM RELEASE AND IMP ACT TO OFFSITE DOSE Using the Flow Element (FE) throat diameter and a material loss rate of [[

                       ]] for the upstream casting over 54 EFPY (resulting in a diameter increase of

[[ ]]), the resu lts of the revised choked flow rate are shown in Table 3-4 as follows: Table 3-4: Choked Flow Results Summary Total Revised Current Licensed Material Eroded Choked FE Throat Material TLAA Thermal Power Loss Rate Throat Flow Diameter Loss Over Choked (CLTP) (initial) (inches/ Diameter Increase (inches) 54 Years Flow Choked Flow (lbs/hr) year) (inches) (%) (inches) . (lbs/hr) [[ ]] The radiological dose increase is proportional to the steam released. As calculated above, the break flow (choked flow) increase for life extension is [[ ]). Therefore, the radiological dose increase is also [[ ]). 9

003N4606-NP Revision 2 Non-Proprietary Information - Class I (Public) The historic material loss rate of 0.004 inches per year over 40 years would have resulted in a [[ ]] diameter opening in the main steam line flow restrictor than the [[

      ]] over 54 EFPY . Therefore, this resulting [[              ]] choked flow and radiological dose from F AC, erosion, and corrosion would be [[           ]] than the originally predicted value based off the historic material loss rate over 40 years. Also, the method used in the calculation of choked flow is detailed in SIL 438 Revision 2 (Reference 18), which is an enhanced method from previous analysis used to generate the results. This method results in a reduced choked flow compared to the more conservative method applied in the original analysis.

3.3 INSPECTION FREQUENCY There is no concern relative to the steam release and associated offsite dose increase due to material loss that would require any augmented inspection of the main steam flow restrictors. The upstream casting is composed of ASTM A351 Grade CF8 material with low molybdenum content <<0.50% Mo) . The available records indicate that centrifugal casting was the manufacturing method for the main steam line flow restrictors. Therefore, the upstream castings of the main steam line flow restrictors are not considered susceptible to thermal aging concerns, and no augmented inspection is necessary . 10

003N4606-NP Revision 2 Non-Proprietary Information - Class I (Public)

4.0 REFERENCES

1. "Insert," 10505425 , Revision 3, 1976.

2. " Upstream Casting," 10505082, Revision 4, 1983.

3. " Downstream Casting," 10505083 , Revision 7, 1978.

4. " Castings, Type 304 Austenitic Stainless Steel," B50YP43 , Revision 14, 1996.

5. O.K. Chopra, "Estimation of Fracture Toughness of Cast Stainless Steels During Thermal Aging in L WR Systems," NUREG/CR-4513 , Revision 1, August 1994.

6. Letter, Christopher I. Grimes (NRC) to Douglas 1. Walters (Nuclear Energy Institute) ,

    "License Renewal Issue No . 98-0030, 'Thermal Aging Embrittlement of Cast Austenitic Stainless Steel Components' ," May 19, 2000.

7. " Casting, Carbon Steel (36000 Min. Yield)," B50YP117, Revision 5, 1979.

8. " Pipe, Seamless, Carbon Steel - 60,000 psi Min. Tensile," B50YP28, Revision 5, 1978.

9. " Carbon Steel for Forged Parts - 70,000 psi Min. Tensile," B50YP68, Revision 5, 1978.

10. Revie, R. Winston, Uhli g's Corrosion Handbook, pp: 233-272, John Wiley & Sons, 2nd Edition, 2000.

11. Recommendations for an Effective Flow-Accelerated Corrosion Program (NSAC-202L-R4). EPR!, Palo A lto, CA: 2013 . 3002000563.

12. " Wall Thinning Due to Erosion Mechanisms," LR-ISG-2012-01 , May 1, 2013.

13 . " Generic Aging Lessons Learned (GALL) Report," NUREG-1801 , Revision 2, December 2010.

14. Shreir, L.L. ; Jarman, R.A. ; Burstein, G.T. , Corrosion, Volumes 1-2, pp: 293-303 ,

Elsevier, 3rd Edition, 1994.

15. Jonas, Otakar. "F AC and Cavitation: Identification, Assessment, Monitoring, Prevention," Combined Cycle Journal, pp. 1-7, Second Quarter 2004.

16. Corrosion Survey Database (COR-SUR), 2002 NACE International.

17. "Design and Performance of General Electric Boiling Water Reactor Jet Pumps,"

APED-5460, September 1968.

18. SIL 438 , Revision 2, " Main Steam Line High Flow Trip Setting," May 132013.

11}}

v t e Letter Sequence Request
CAC:MF9757, (Approved, Closed)
Initiation Request, Request, Request, Request, Request, Request, Request, Request, Request Acceptance, Acceptance Supplement Administration Meeting, Meeting Questions 16 November 2017 29 November 2017 13 December 2017 13 December 2017 27 December 2017 9 January 2018 22 January 2018 8 February 2018 12 February 2018 7 March 2018 8 March 2018 6 March 2018 9 March 2018 29 March 2018 19 March 2018 28 March 2018 12 April 2018 30 April 2018 3 May 2018 Answers Results Approval, Approval Other: ML17156A098, ML17347A383, ML17348B142, ML18078A747, ML18107A504, ML18120A135, ML18124A190, ML18127A034, ML18129A356, ML18143B396, ML18151A082, ML18155A550, ML18241A321
MONTHYEAR2018-03-29 [Table View]

RBG-47818, Response to License Renewal Application NRC Request for Additional Information - Set 7

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Dear Sir or Madam :

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SUMMARY

1.0 INTRODUCTION

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4.0 REFERENCES

1.0 INTRODUCTION

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