Text

Update of Aging Management Program Audit Q&A Database
	ML073230356
Person / Time
Site:	Vermont Yankee
Issue date:	11/14/2007
From:	Ted Sullivan; Entergy Nuclear Operations
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	BVY 07-079
	Download: ML073230356 (153)
	v • d • e

EntergyNuclear Operations, Inc. Cl Vermont Yankee

--Entergy P.O. Box 0500 185 Old Ferry Road Brattleboro, VT 05302-0500 Tel 802 257. 5271 November 14; 2007 BVY 07-079 ATTN: Document Control Desk U.S. Nuclear Regulatory Commission Washington, DC 20555-0001

Reference:

1. Aging Management Program/Aging Management Review (AMP/AMR) -,

Audit Q&A Database, Revision 5, dated March 27, 2007 *:

Subject:

Vermont Yankee Nuclear Power Station License No. DPR-28 (Docket No. 50-271)

Update of Aqing Management Program Audit Q&A Database This'letter provides Revision 6 of the AMP/AMR audit question-and-answer (Q&A) database. In addition to providing a complete current version of the database, this update addresses Staff questions from the Environmentally Assisted Fatigue (EAF) audit portion of the NRC's Vermont Yankee License Renewal Application Aging Management Program review process. Questions # 387 through #392 of this database remain open and are submitted herewith for Staff review. All other responses were previously reviewed and are considered closed. The enclosed database (Attachment 1) updates and supersedes Reference 1.

This letter contains no new commitments.

Should you have any questions concerning this matter, please contact Mr. David ,Mannai at (802) 258-5422.

I declare under penalty of perjury that the foregoing is true and correct.

Executed on November14, 2007.

Sincerely, un*W~k Fn Ted A. Sullivan

-(, AdL0iVA4 Site Vice Pr side Vermont Yan-ee Nuclear Power Station Attachment cc listing (next page)

,?

BVY 07-079 Page 2 of 2 cc: Mr. James Dyer, Director U.S. Nuclear Regulatory Commission Office O5E7 Washington, DC 20555-00001 Mr. Samuel J. Collins Regional Administrator, Region 1 U.S. Nuclear Regulatory Commission 475 Allendale Road King of Prussia, PA 19406-1415 Mr. Jack Strosnider, Director U.S. Nuclear Regulatory Commission Office T8A23 Washington, DC 20555-00001 Mr. Jonathan Rowley, Senior Project Manager U.S. Nuclear Regulatory Commission 11555 Rockville Pike MS-O-1 1F1 Rockville, MD 20853 Mr. Mike Modes USNRC RI 475 Allendale Road King of Prussia, PA 19406 Mr. James Kim, Project Manager Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation U.S. Nuclear, Regulatory Commission Mail Stop 0 8 C2A Washington, DC 20555 USNRC Resident Inspector Entergy Nuclear Vermont Yankee, LLC PO Box 157 Vernon, Vermont 05354 Mr. David O'Brien, Commissioner VT Department of Public Service 112 State Street - Drawer 20 Montpelier, Vermont 05620-2601 Diane Curran, Esq.

Harmon, Curran, Spielberg & Eisenberg, LLP 1726 M Street, N.W., Suite 600 Washington, DC 20036

BVY 07-079 Attachment 1 Vermont Yankee Nuclear Power Station License No. DPR-28 (Docket No. 50-271)

AMP/AMR Audit Q&A Database Revision 6

VYNPS LRA - All AMPIAMR Audit Items, Revision 6 Item Request Response 1 A-K-01 The LRA, Appendix B identifies the commitments for AMP enhancements.

Please explain where the commitments for the various AMP enhancements to bring the Consistent with how other NRC commitments are tracked, VY will enter the particular AMP in conformance to the GALL Report recommendations are made? How commitments associated with License Renewal into the Entergy Commitment are these commitments tracked to closure? Database System (LRS) per procedure EN-LI-1 10. We will do this when requested by the LR Project Manager who has a tracking item to define how all planned actions are tracked.

2 B.1.1-L-01 Yes, gray cast iron components subject to aging management review are included in Program Description Item - The GALL states, "Gray cast iron, which is included under the VYNPS selective leaching program. Reference LRA Section B.1.25 and Table the definition of steel, is also subject to a loss of material due to selective leaching, 3.3.2-8.

which is an aging effect managed under Chapter XI.M33, 'Selective Leaching of Materials'." The LRA states, "This program includes (a) preventive measures to mitigate corrosion and (b) inspections to manage effects of corrosion on the pressure-retaining capability of buried carbon steel, stainless steel, and gray cast iron components." Are gray cast iron components included in the VYNPS selective leaching program?

3 B.1.1-L-02 LR Commitments 44 and 48 Program Description Item - The LRA states, "A focused inspection will be performed within the first 10 years of the period of extended operation...." What is the extent of the If a focused inspection is required during the first 10 years of the period of extended focused inspection at the start of the period of extended operation? operation, it will be conducted in accordance with the criteria of NUREG-1 801,Section XI.M34, Buried Piping and Tanks Inspection.

Modified Question: Program Description Item -The LRA states, "A focused inspection will be performed within the first 10 years of extended operation... "On what areas will In section 4 of XI.M34 it states that any credited inspection should be performed in the "focused inspection" be focused? areas with the highest likelihood of corrosion problems, and in areas with a history of corrosion problems. This defines the focused inspection that will be performed at VYNPS which will also include buried piping that has experienced external corrosion problems and areas that have conditions such as exposure to groundwater that could increase the likelihood of corrosion of buried piping.

Commitment 44 is provided to revise the guidance for perfomring buried piping inspections to include a provision that will allow for an opportunistic inspection or inspection via a method that allows assessment of pipe conditoin wihtout excavation within the 10 year period. In addition to this, Commitment 48 is provided to perform an internal inspection of the underground Service Water piping before the period of extended operation.

4 B.1.1-L-03 The basis for exclusion of tanks from the Buried Piping Inspection Program is that Scope of Program Element - The GALL Report states, "The program relies on none of the metal tanks subject to aging management review are buried. Therefore, preventive measures such as coating, wrapping and periodic inspection for loss of aging of tanks is managed by other programs. Reference LRA Sections 3.2.2.2.9 material caused by corrosion of the external surface of buried steel piping and tanks." and 3.4.2.2.5, and Section 3.3 Tables (The only buried tank in the auxiliary systems The LRA states, "The VYNPS program does not inspect tanks. There are no buried is fiberglass.) [LAP 4/12/06]

steel tanks subject to aging management review." What is the basis for including piping but excluding tanks? These were discussed in interview and the responses were subsequently written.

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Item Request Response 5 B.1.1-L-04 License Renewal Commitment #1 Parameters Monitored/Inspected Element - The GALL Report states, "Coatings and wrappings are inspected by visual techniques." The LRA states, "Guidance for Vermont Yankee will enhance PP 7030, Structures Monitoring Program Procedure, performing examinations of buried piping will be enhanced to specify that coating to provide additional guidelines for inspections of buried pipe and underground degradation and corrosion are attributes to be evaluated." What is the VYNPS structures. Attributes to be considered will include:

commitment number associated with this enhancement? Buried piping is visually examined for evidence of corrosion damage or coating defects." A review of PP 7030, 1. improved definition of the scope of underground piping inspections Section 4.3, does not identify the parameters that pertain to corrosion damage or 2. define the condition of coatings to be inspected, including adhesion and coating defects. Is this the guidance that VY intends to enhance? discontinuities.

3. define the need to inspect piping underneath failed coatings

4. provide acceptance criteria, including removal of rust and an evaluation of remaining wall thickness against the minimum wall thickness requirements

5. provide instructions to notify Engineering for an inspection of any underground structures unearthed during excavation of piping.

6 B.1.1-L-05 Buried components are inspected when excavated during maintenance. The Detection of Aging Effects Element - The GALL Report states, "Inspections substituted exception merely states that alternate methods may be used to inspect buried for inspections requiring excavation solely for the purpose of inspection. Methods such components. Reference LRA Section B.1.1.

as phased array UT technology provide indication of wall thickness for buried piping without excavation. Use of such methods to identify the effects of aging is preferable to excavation for visual inspection, which could result in damage to coatings or wrappings." How are buried components that cannot be examined by UT, due to, e.g.,

either material or size, examined?

7 B.1.2-P-1 As indicated in LRA Tables 3.3.2-13-5 and 3.3.2-13-36, the excepted welded Exceptions granted under the current license are not assumed to apply to period of connection is subject to aging management review for potential spatial interaction in extended operation. Please confirm that the excepted weld is outside the scope of accordance with 10 CFR 50.54 (a)(2). As stated in LRA Section B.1.2, exception license renewal. Also, explain why it need not be inspected at least once in each Note 1, the welded connection need not be inspected because it is in a section of inspection interval. piping that is Safety Class 0 and has no license renewal function in accordance with 10 CFR 54.4 (a)(1) or (a)(3).

8 B.1.7-H-01 The BWR Vessel Internals Program includes provisions to notify the NRC if VYNPS BWRVIP utilities have made a commitment that the NRC will be notified by a BWRVIP does not implement a BWRVIP recommendation. Exceptions to the NUREG-1801 licensee of their decision to not fully implement a BWRVIP report, as approved by the programs that invoke specific BWRVIP reports are identified in Appendix B of the NRC staff, within 45 days of the reports approval. Please clarify the exceptions for not LRA. Reference LRA Section B.1.7 and LRPD-02 (AMPER) Section 4.7 The IVVI fully implementing BWRVIP report by VYNPS. Did VYNPS define any new cases of not program procedure is ENN-DC-135, and the current revision includes the fully implementing BWRVIP in the VYNPS LRA? requirements of BWRVIP 94 Revision 1. VY has prepared a technical justification to defer the jet pump beam examinations to align with the refueling outage schedule as allowed by BWRVIP-94 (Revision in place at time of deviation). The BWRVIP requirements are based on 24 month cycles while VY is on a 18 month cycle. The UT examinations of the Jet Pump beams are scheduled for the next refueling outage RFO 26 (2007). BWRVIP 94 Revision 1, Section 3.5 provides guidance on the reporting requirements. A BWRVIP letter dated 12/20/2005 requires implementation by 8/1/2006. This is also addressed in the latest revision of ENN-DC-135.

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Response

Item Reauest ResDonse 9 B.1.7-H-02 License Renewal Commitment # 29.

In the VYNPS LRA, pages B-28 & C-5, an exception to BWRVIP-25 is taken. UT & RAI B.1.7-H-02 Enhanced VT-1 examinations are used to detect cracking and verify the integrity of a critical number of rim hold-down bolts. VT-3 examination is used to detect general This exception came from TJ-2004-01 in PP 7027. The BWR Core Plate Inspection condition. Please provide further justification for the aging management of the and Flaw Evaluation Guideline (BWRVIP-25) recommended a UT or EVT cracking, since VT-3 cannot detect cracking. If EVT-1 cannot be performed, please examinations of core plate rim hold-down bolts for all plants that have not installed provide alternative for review and approval. core plate wedges. These bolts are the only location in the core plate requiring inspection. Utilities have determined the EVT-1 examinations are extremely difficult to perform and are of limited value. The Inspection committee of the BWRVIP has attempted to develop a UT technique, and has had limited success. However, the UT examination can only be performed on a limited number of existing bolt configurations and delivery hardware for the inspection equipment has not been developed.

VY will either install core plate wedges or complete an analysis, including TLAA, to support continued inspection in accordance with BWRVIP- 25.

CLOSED TO RAI B.1.7-H-02 10 B.1.7-H-03 The response to this question is the same as Question 9, i.e. the UT inspection is In the VYNPS LRA, page B-29, the applicant identified a VT-3 examination as a challenging and the BWRVIP is working developing an inspection method.

baseline. The baseline inspection described in BWRVIP is the first inspection that satisfies the guidelines in BWRVIP. Since VT-3 does not satisfy the BWRVIP guidelines, the inspection cited does not provide a baseline. Please explain how the BWRVIP guideline will be met.

11 B.1.7-H-04 LRA Amendment In the VYNPS LRA, page B-27, (BWRVIP-76) Recent industry experience indicates that partial through-wall cracks from the inside diameter are possible. (They have been Accessible regions of the core shroud welds H1 ,H2 & H3 are UT examined lAW detected at Plant Hatch.) How will cracking initiated from the inside surface of BWRVIP-76. Portions of the total accessible regions of H1 ,H2 & H3 are VYNPS's core shroud welds H1, H2, and H3 be managed? characterized as design reliant analysis performed by the shroud repair designer determined the minimum design reliant weld lengths.

Continuous question: Does applicant plan to revise LRA? If yes, Please provide the exact wording for LRA supplement. LRA Section B.1.7 will be changed as follows:

1. The exception to the BWR vessel internals program related to the core shroud (page B-27) will be deleted.

2. Exception Note #1 on page B- 29 will be deleted.

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Item Request Response 12 B.1.7-H-05 License Renewal Commitment #36 In the VYNPS LRA, page B-28 (BWRVIP-18 and BWRVIP-41) BWRVIP-18 states that inspection technique development needed for the thermal sleeve welds is being VYNPS will inspect the hidden jet pump thermal sleeve and core spray thermal addressed by the BWRVIP inspection committee as a high priority item (since 1996). sleeve welds in accordance with BWRVIP-18 and 41 once the technology is The Final License Renewal SER for BWRVIP-41 states that aging management review developed and approved by the NRC.

of the nozzle thermal sleeve (jet pump inaccessible welds) will be provided by individual applicants. Please provide plant-specific justification/commitment to demonstrate that If technology has not been developed and approved by the NRC at least two years these inaccessible welds (BWRVIP-18,4) will be adequately managed during the period prior to the period of extended operation, VYNPS will initiate plant-specific action to of extended operation. resolve this issue. That plant specific action may be justification that the welds do not require inspection by expanding the discussions summarized below.

The VYNPS hidden jet pump welds (TS-1 &2) are far enough into the nozzle that failure at these welds would not result in the thermal sleeve disengaging from the nozzle. With the thermal sleeve still engaged, structural integrity of the rest of the jet pump is maintained. If the VYNPS jet pump thermal sleeve or riser piping severed, it would be detected through jet pump monitoring, and the unit would be shut down to effect a repair of the break. The effects of short operation on the affected jet pump nozzle would be evaluated.

The VYNPS hidden core spray welds (CSTS-1,2&3) are far enough into the nozzle that failure at these welds would not result in the thermal sleeve disengaging from the nozzle. With the thermal sleeve still engaged, structural integrity of the rest of the core spray ring header is maintained. If the VYNPS core spray thermal sleeve or ring header piping is severed, it would be detected through the core spray sparger break detection monitoring system. The unit would be shutdown to effect repair of the break. If the core spray system is operated during this time, the effect of that operation on the affected core spray nozzle would be evaluated.

The VYNPS hidden core spray welds (CSTS-1,2&3) are far enough into the nozzle.

that failure at these welds would not result in the thermal sleeve disengaging from the nozzle. With the thermal sleeve still engaged, structural integrity of the rest of the core spray ring header is maintained. If the VYNPS core spray thermal sleeve or ring header piping is severed, it would be detected through the core spray sparger break detection monitoring system. Once the technology is developed VY will inspect these welds lAW BWRVIP-1 8.

If technology has not been developed and approved by the NRC at least two years prior to the period of extended operation, VYNPS will initiate plant-specific action to resolve this issue.. That plant specific action may be justification that the welds do not require inspection by expanding the discussions summarized below.

The VYNPS hidden jet pump welds (TS-1&2) are far enough into the nozzle that failure at these welds would not result in the thermal sleeve disengaging from the nozzle. With the thermal sleeve still engaged, structural integrity of the rest of the jet pump is maintained. If the VYNPS jet pump thermal sleeve or riser piping severed, it would be detected through jet pump monitoring, and the unit would be shut down to effect a repair of the break. The effects of short operation on the affected jet pump nozzle would be evaluated.

The VYNPS hidden core spray welds (CSTS-1,2&3) are far enough into the nozzle that failure at these welds would not result in the thermal sleeve disengaging from the nozzle. With the thermal sleeve still engaged, structural integrity of the rest of Page4of 150 11/14/20071:37:58 1111412007 PM 1:37.58 PM Page 4 of 150

Item Request Response the core spray ring header is maintained. If the VYNPS core spray thermal sleeve or ring header piping is severed, it would be detected through the core spray sparger break detection monitoring system. The unit would be shutdown to effect repair of the break. If the core spray system is operated during this time, the effect of that operation on the affected core spray nozzle would be evaluated.

The VYNPS hidden core spray welds (CSTS-1,2&3) are far enough into the nozzle that failure at these welds would not result in the thermal sleeve disengaging from the nozzle. With the thermal sleeve still engaged, structural integrity of the rest of the core spray ring header is maintained. If the VYNPS core spray thermal sleeve or ring header piping is severed, it would be detected through the core spray sparger break detection monitoring system. Once the technology is developed VY will inspect these welds lAW BWRVIP-18.

13 B.1.7-H-06 TE-2003-0021 from Appendix C of PP 7027 will be provided during on-site audit.

In the VYNPS LRA, page B-28 (BWRVIP-41) The VYNPS LRA states that flaws were References used to prepare TE-2003-0021 will be available for on-site review upon identified through UT examinations. Please provide detailed inspection evaluation, request.

scope expansion and corrective action information for the staff's review. Flaw evaluations were performed for the jet pump (JP) diffuser welds, JP riser welds, and the core spray collar welds. TheJP riser flaw evaluation calculation number is VYC-2400. The core spray collar weld flaw evaluation report number is VY-RPT-05-00015. 100% of the JP diffuser welds were inspected by UT in RFO 21 (1999). The flawed diffuser welds were re-inspected by UT in RFO 23 (2002) with little change in flaw sizes. 26 of 30 JP riser welds were UT inspected in RFO 20 (1998) and 4 welds were inspected by VT-1 with cleaning. The flawed riser welds were re-inspected by UT in RFO 22 (2001) with no crack growth on 2 welds and two previous indications were determined to be due to UT transducer lift-off. 100 % of the core spray collar welds were examined by UT in 1996. The flawed collar welds were re-inspected by UT in RFO 22 (2001) with no change in flaw sizes. The flawed JP diffuser/riser welds and the Core Spray collar welds are scheduled to be inspected by UT during RFO 26 (2007). Future re-inspections will be performed in accordance with BWRVIP requirements.

14 B.1.7-H-07 License Renewal Commitment #2 In the VYNPS LRA, page B-31 (BWRVIP-26) The VYNPS LRA states that an inspection will be performed for the first 12 years of the period of extended operation NUREG-1801 requires inspection of 5% of the Top Guide during the first six years of (PEO). Please clarify what inspections (if any) will be performed for the remaining PEO. the period of extended operation, and inspection of an additional 5% during the second 6 years of the period of extended operation. VYNPS has committed to Need commitment for the re-inspection. Need word. these examinations in the current LRA.

In response to the discussions relative to this question, VYNPS will inspect an additional 5% of the Top Guide during the third 6 years of the period of extended operation. (Commitment #2) 15 B.1.8-L-01 Noadditional tests or examinations are performed under the Containment Leak Rate Operating Experience Element - The LRA states, "A QA audit in 2001 revealed latent Testing Program.

non-compliance with station administrative and Appendix J implementing procedures." The term latent in this context means: not currently affecting program effectiveness, Please clarify the meaning of 'latent" in this context. but with the potential for affecting program effictiveness if not corrected. While technical details were followed, administrative processes, associated with test Added:Scope of Program item. Are any other examinations/tests performed, in addition record retention, were implemented outside the established requirements. This to the integrated leakage rate and the local leakage rate tests? procedural non-compliance, if not corrected, could have diminished the effectiveness of the program. Reference VYNPS Audit Report VT-2001-26.

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Item Request Response 16 B.1.9-K-01 ASTM D2276 provides guidance on determining particulate contamination using a Please demonstrate that the guidelines provided in 02276 are consistent with or more field monitor. It provides for rapid assessment of changes in contamination level stringent than the guidelines provided in D6217 to justify the use of D2276 only. without the time delay required for rigorous laboratory procedures. It also provides a laboratory filtration method using a 0.8 micron filter. ASTM D6217 provides guidance on determining particulate contamination by sample filtration at an off-site laboratory. Neither method contains acceptance criteria or is more stringent than the other. Thus, there is no reason to use both methods. Since ASTM D2276 is an accepted method of determining particulates and is a method recommended by ASTM D975, to which VYNPS is committed by Technical Specifications, the D2276 method is used at VYNPS.

17 B.1.9-K-02 As stated in the program description in LRA Section B.1.9, sampling and analysis Are the guidelines provided in D4057 addressed in this program? If not, please justify activities are in accordance with technical specifications on fuel oil purity and the excluding this standard as an exception to the GALL Report recommendations. guidelines of ASTM standards D4057-88 and D975-02 (or later revisions of these standards). Reference LRA Section B.1.9, Program Description.

18 B.1.9-K-03 Vermont Yankee purchases un-dyed, low sulfur #2 diesel fuel for use in safety-Please indicate what additives, if any, are provided by the fuel oil supplier. Please related systems. Additives are not used by Vermont Yankee or the fuel supplier.

provide a copy of a recent fuel oil procurement specification or supplier declaration The diesel fuel currently comes from Ultramar (a Canadian refinery) to a local which indicates what fuel oil additives are included as well as any tests that may have supplier. The refinery blends fuel to meet a given specification and may use some been performed by the fuel oil supplier or by VYNPS. additives such as cetane enhancers. Refinery use of additives is not described in their specification and is outside the control of the end user. Biocides have never been added to the onsite fuel supply.

19 B.1.9-K-04 As stated in LRA Section B.1.9, exception note 2, plant operating experience has Please provide the technical justification for not adding fuel oil additives. not indicated a need for additives. Reference LRA Section B.1.9, exception note 2.

Fuel additives are generally required for three reasons. These are to maintain the stability of the fuel oil, change the properties of the fuel oil (e.g. increase the ignition quality) or to prevent bacterial or mold growth in the fuel oil. The addition of biocides may degrade some of the other fuel oil properties such as increasing the filterable solids loading.

For th6 past 10 years, VYNPS has been buying high quality fuel oil from Ultramar in Canada. Our deliveries are timed to the arrival of new rail cars in Vermont from this refinery. We specify very high quality fuel oil and ensure that it and the delivery trucks do not contain any contaminants. Monthly analyses of diesel fuel oil from the top, middle and bottom of the Main Fuel Oil Storage Tank have not produced any indications of fuel oil deterioration or the presence of water or sediment. Since mold and bacteria grow in the water fuel oil interface, we have no need for biocides.

Diesel generator performance associated with the quality of the diesel fuel oil has been excellent. Thus, there is no need for fuel oil additives.

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Item Reauest ResDonse 20 B.1.9-K-05 Commitments 46 and 47 Please describe what parameters are monitored or inspected and indicate what The Diesel Fuel Monitoring Program monitors fuel quality and levels of water in the guidance is used for fuel oil sampling. Please provide a copy of a representative plant fuel oil. ASTM D4057-88 (or a later revision of this standard), Standard Practice for procedure for fuel oil sampling. Manual Sampling of Petroleum and Petroleum Products, is used for guidance on oil sampling. Safety-related diesel fuel oil is analyzed according to ASTM D975-02 (or a later revision of this standard). ASTM D1796 is used to check for water and sediment. Determination of particulates is according to ASTM Standard D2276.

Reference LRPD-02 (AMPER) Section 4.9. Exceptions to NUREG-1801 Section XI.M30 parameters monitored/inspected are described in LRA Section B.1.9.

Procedure OP-4613 is available for on-site review in the program basis documents.

Commitments are provided for program enhancements to include sampling of the fire pump day tank, the JDDG storage tank and the common portable fuel oil storage tank.

21 B.1.9-K-06 As stated in LRA Section B.1.9, the Diesel Fuel Monitoring Program is consistent Is multi-level sampling used to detect the presence of contaminants in the fuel oil and, if with NUREG-1 801,Section XI.M30 for the detection of aging effects attribute. As not, please provide the technical justification for the approach used at the plant? described in NUREG-1801, periodic multi-level sampling is used to provide assurance that fuel oil contaminants are below unacceptable levels. Reference LRA Section B.1.9 and LRPD-02 (AMPER) Section 4.9.

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Item Request Response 22 B.1.9-K-07 Commitments 3 Are the interior surfaces of the fuel oil tanks visually inspected and, if so, provide a copy As stated in LRA Section B.1.9, the Diesel Fuel Monitoring Program is consistent of a representative plant procedure used for the tank inspection? I with NUREG-1801,Section XI.M30 for the detection of aging effects attribute. As described in NUREG-1 801, the fuel oil storage tank is periodically drained, cleaned and visually inspected to detect potential degradation. Reference LRA Section B.1.9 and LRPD-02 (AMPER) Section 4.9. PM Activity 3 of PM Basis M1 18 is available for on-site review in the program basis document.

The diesel day tanks are 800 gallon tanks located above ground and adjacent to the emergency diesels in separate rooms. The design of the tanks does not provide access for cleaning. The fuel oil for these tanks is supplied from the Main Fuel Oil Storage Tank. The suction for the transfer pumps is located 4" off of the bottom of the tank. Chemistry samples both the Main Tank and the Day Tanks from the bottom of the tanks. Water and/or sediment in the Main Storage Tank would be detected prior to it being transferred to the Day Tanks.

Each of the Emergency Diesel Generators is run for 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months monthly with each diesel using approximately 200 gallons of fuel oil per hour. This ensures that the fuel oil is turned over every month and that there are no stability issues. There have been no indications of water and sediment in the quarterly analyses from these tanks. Since VYNPS is sampling from the bottom of these tanks and has not detected problems with the fuel oil, there is no reason to drain and clean the tanks.

The John Deere Diesel Generator (JDDG) is run under load monthly for 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months . This diesel uses 10 gallons per hour and the surveillance requires verification of auto feed. The fire pump diesel is operated during monthly and quarterly surveillance tests. Thus, the fuel in the metal tanks associated with the JDDG and fire pump diesels is turned over frequently.

Commitment 3 is provided to enhance the Diesel Fuel Monitoring Program to specify UT measurements of the fuel oil storage and fire pump storage (day) tank bottom surfaces every 10 years during tank cleaning and inspection.

23 B.1.9-K-08 Commitments 4 Are UT measurements conducted on the fuel oil tank bottoms? How often are these A 1996 ultrasonic thickness measurement of the fuel oil storage tank bottom surface measurements taken and provide a copy of a representative plant procedure which revealed no significant degradation. The Diesel Fuel Monitoring Program includes governs these measurements? an enhancement to perform UT measurements of the fuel oil storage tank bottom surface every 10 years during the period of extended operation. Reference LRA Section B.1.9. WO 94-08951, with the results of the 1996 UT measurement, is available for on-site review in the program basis document.

Commitment 4 is provided to enhance the Diesel Fuel Monitoring Program to specify UT measurements of the fuel oil storage and fire pump storage (day) tank bottom surfaces with an acceptance criteria greater than or equal to sixty percent Tnom.

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Item Request Response 24 B.1.9-K-09 The Diesel Fuel Monitoring Program is consistent with NUREG-1801, Section How often are the fuel oil in the tanks sampled? Is this data trended and what criteria is XI.M30 for the monitoring and trending attribute. As described in NUREG-1 801, used to initiate corrective actions? monitoring (sampling) and trending occurs at least quarterly, and in accordance with VYNPS Technical Specifications (monthly). Reference LRA Section B.1.9 and Technical Specification 4.10.C.2. Filterable solids acceptance criterion is = 10 mg/l.

Water and sediment acceptance criterion is = 0.05%, UT acceptance criterion will be = 60% nominal thickness. Reference LRA Section B.1.9 and LRPD-02 (AMPER)

Section 4.9.

25 B.1.9-K-10 The review of plant operating experience did not reveal any component failures Have there been any component failures related to the quality of the fuel oil which led to related to the quality of the fuel oil that led to the loss of intended function.

the loss of intended function? Reference LRA Section B.1.9 and LRPD-05 (OE Report).

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Item Request Response 26 B.1.10-N-01 LRA Amendment The results of the EQ of electrical equipment in LRA Section 4.4. indicate equipment identified in the TLAA. The important attributes of a re-analysis are the analytical VYNPS may perform re-analysis of an aging evaluation in order to extend the methods, the data collection, the reduction methods, the underlying assumptions, the qualification of electrical components under 10 CFR 50.49 on a routine basis as part acceptance criteria, and corrective actions. Provide information on these important of the plant's EQ program. Important attributes for the re-analysis of an aging attributes of re-analysis of an aging evaluation of electrical equipment identified in the evaluation include analytical methods, data collection and reduction methods, TLAA to extend the qualification under 10 CFR 50.49(e). underlying assumptions, acceptance criteria, and corrective actions.

VYNPS may apply this re-analysis program to EQ components now qualified for the current operating term. A re-analysis program that meets the conditions defined in the GALL report for important attributes, is an acceptable AMP for license renewal under option 10 CFR 54.21 (c)(1)(iii).

LRA Appendix B.1 .10 will be revised to add the following:

EQ Component Re-analysis Attributes The re-analysis of an aging evaluation is normally performed to extend the qualification by reducing excess conservatism incorporated in the prior evaluation.

Reanalysis of an aging evaluation to extend the qualification of a component is performed on a routine basis pursuant to 10 CFR 50.49(e) as part of an EQ program. While a component life limiting condition may be due to thermal, radiation, or cyclical aging, the vast majority of component aging limits are based on thermal conditions. Conservatism may exist in aging evaluation parameters, such as the assumed ambient temperature of the component, an unrealistically low activation energy, or in the application of a component (de-energized versus energized). The re-analysis of an aging evaluation is documented according to the station's quality assurance program requirements that require the verification of assumptions and conclusions. As already noted, important attributes of a re-analysis include analytical methods, data collection and reduction methods, underlying assumptions, acceptance criteria, and corrective actions (if acceptance criteria are not met).

These attributes are discussed below.

Analytical Methods:

The analytical models used in the re-analysis of an aging evaluation are the same as those previously applied during the prior evaluation. The Arrhenius methodology is an acceptable thermal model for performing a thermal aging evaluation. The analytical method used for a radiation aging evaluation is to demonstrate qualification for the total integrated dose (that is, normal radiation dose for the projected installed life plus accident radiation dose). For license renewal, one acceptable method of establishing the 60-year normal radiation dose is to multiply the 40-year normal radiation dose by 1.5 (that is, 60 years/40 years). The result is added to the accident radiation dose to obtain the total integrated dose for the component. For cyclical aging, a similar approach may be used. Other models may be justified on a case-by-case basis.

Data Collection and Reduction Methods:

Reducing excess conservatism in the component service conditions (for example, temperature, radiation, cycles) used in the prior aging evaluation is the chief method used for a re-analysis. Temperature data used in an aging evaluation is to be conservative and based on plant design temperatures or on actual plant temperature data. When used, plant temperature data can be obtained in several ways, including monitors used for Technical Specification compliance, other installed monitors, Page 10 of 150 1111412007 1:37.68 PM 11/14/20071:37:58 PM Pae 10 of 150

Item Request Response measurements made by plant operators during rounds, and temperature sensors on large motors (while the motor is not running). A representative number of temperature measurements are conservatively evaluated to establish the temperatures used in an aging evaluation. Plant temperature data may be used in an aging evaluation in different ways, such as (a) directly applying the plant temperature data in the evaluation, or (b) using the plant temperature data to demonstrate conservatism when using plant design temperatures for an evaluation.

Any changes to material activation energy values as part of a re-analysis are to be justified on a plant-specific basis. Similar methods of reducing excess conservatism in the component service conditions used in prior aging evaluations can be used for radiation and cyclical aging.

Underlying Assumptions:

EQ component aging evaluations contain sufficient conservatism to account for most environmental changes occurring due to plant modifications and events. When unexpected adverse conditions are identified during operational or maintenance activities that affect the normal operating environment of a qualified component, the affected EQ component is evaluated and appropriate corrective actions are taken that may include changes to the qualification bases and conclusions.

Acceptance Criteria and Corrective Actions:

The re-analysis of an aging evaluation could extend the qualification of the component. If the qualification cannot be extended by re-analysis, the component is to be refurbished, replaced, or re-qualified prior to exceeding the period for which the current qualification remains valid. A re-analysis is to be performed in a timely manner (that is, sufficient time is available to refurbish, replace, or re-qualify the component if the re-analys is unsuccessful).

27 B.1.10-N-02 The EQ program (10 CFR 50.49) does not require environmental monitoring, GALL X.E1, Environment Qualification (EQ) of Electric Components, under "Parameter because the EQ components are qualified based on conservative bounding plant Monitored/Inspected" states that EQ component qualified life is not based on condition environments. The VYNPS EQ program, consistent with GALL X.E1, ensures that or performance monitoring. However, pursuant to Regulatory Guide 1.89, Rev. 1, such the components covered by the program are replaced at the end of the qualified life monitoring programs are an acceptable basis to modify a qualified life through or the qualified life is modified by analysis in accordance with the applicable analysis. Monitoring or inspection of certain environmental conditions or component regulations governing the program.

parameters may be used to ensure that the component is within the bounds of its qualified basis, or as a means to modify the qualified life. Provide a detailed description of a monitoring program to modify the qualified life of EQ components through re-analysis and how the actual operating environment is determined.

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Item Request Response 28 B.1.10-N-03 The EQ program is a qualification program that assures SSCs are replaced prior to Discuss operating experience of the existing EQ program. Show where an existing exceeding qualified life beyond that date when unacceptable aging degradation may program has succeeded and where it has failed in identifying aging degradation in a occur. The review of OE identified no conditions in which the program failed to timely manner. identify unacceptable aging degradation. License Event Report (LER) 97-20 notified the NRC staff of program deficiencies including non-conservative analytical methods. Supplementary and confirmatory analyses were completed because conditions in the EQ analyses were determined to be non-conservative. This OE demonstrates that the corrective action process is used to document program deficiencies and track corrective actions when necessary.

QA audits in 2000 and 2002 identified deficiencies related to maintenance and content of program documentation. A 2004 QA audit and engineering program health report determined the program is effective and being administered and maintained in a manner that meets regulatory requirements and commitments.

29 B.1.11-P-1 LR Commitment 27 Please clarify the basis for excluding the impact of environmental factors for critical locations during the period of extended operation. The impact of environmental factors on fatigue at critical locations during the period of extended operation will be addressed as stated in the following commitment.

Prior to entering the period of extended operation, for each of the seven locations that may exceed a CUF of 1.0 when considering environmental effects, VYNPS will implement one or more of the following: (1) further refinement of the fatigue analyses to lower the predicted CUFs to less than 1.0; (2) management of fatigue at the affected locations by an inspection program that has been reviewed and approved by the NRC (e.g., periodic non-destructive examination of the affected locations at inspection intervals to be determined by a method acceptable to the NRC); (3) repair or replacement of the affected locations. Should VYNPS select the option to manage environmental-assisted fatigue during the period of extended operation, details of the aging management program such as scope, qualification, method, and frequency will be provided to the NRC prior to the period of extended operation. Reference LRA Section 4.3.

30 B.1.12.1-L-01 LR Commitment 30.

Program Description Item - The GALL states, "The AMP also includes periodic LRA Amendment inspection and testing of the halon/carbon dioxide (C02) fire suppression system." The LRA does not address the halon/carbon dioxide (C02) fire suppression system. On The Halon 1301 suppression system provides fire suppression only for the computer what basis does the LRA not address the halon/carbon dioxide (C02) fire suppression room. There are no Appendix A, SER commitments or Appendix R commitments system? requiring the Halon 1301 suppression system. Therefore, it is not subject to aging management review. Aging effects for components in the C02 system are managed by the System Walkdown Program. Reference LRA Section B.1.12.1, exception note 1; LRA Table 3.3.2-9; and AMRM-17 (Aging Management Review of the Fire Protection - Water System).

C02 system Functional Testing is performed in accordance with TRM 4.13.D Surveillance Requirements. [LRA Amendment 26]

VY will perform C02 system walkdowns every 6 months starting no later than the beginning of the period of extended operation. (LR Commitment 30) 1.1/4/207... 37:8. PMP.g.12... 15 11114120071 7.*58PM Page 12 of 150

Item Request Response 31 B.1.12.1-L-02 LRA Amendment Scope of Program Element - The GALL states, "The AMP also includes management of The computer room fire suppression is provided by a Halon 1301 suppression the aging effects on the intended function of the halon/CO2 fire suppression system." system. There are no Appendix A, SER commitments or Appendix R commitments The LRA states, "This program is not necessary to manage aging effects for halon fire requiring the Halon 1301 suppression system. Therefore, it is not subject to aging protection system components." What program will manage aging effects on halon management review. Reference AMRM-17 (Aging Management Review of the Fire system components? Protection - Water System).

C02 system Functional Testing is performed in accordance with TRM 4.13.D Surveillance Requirements. [LRA Amendment 26]

32 B.1.12.1-L-03 The computer room fire suppression is provided by a Halon 1301 suppression The LRA states "the Halon 1301 suppression system is not subject to aging system. There are no Appendix A, SER commitments or Appendix R commitments management review. Aging effects for components in the C02 system are managed by requiring the Halon 1301 suppression system. Therefore, it is not subject to aging the System Walkdown Program." Explain rational for why the Halon 1301 suppression management review. Reference AMRM-17 (Aging Management Review of the Fire system is not subject to review. Protection - Water System).

33 B.1.12.1-L-04 LR Commitment 9 Parameters Monitored/Inspected Element - The GALL Report states, "The diesel-driven fire pump is under observation during performance tests such as flow and discharge Yes - License Renewal Commitment #9 addresses this enhancement tests, sequential starting capability tests, and controller function tests for detection of any degradation of the fuel supply line." The LRA states, "Procedures will be enhanced to state that the diesel engine sub-systems (including the fuel supply line) shall be observed while the pump is running." Is there a VYNPS commitment number associated with this enhancement?

34 B.1.12.1-L-05 LRA Amendment Detection of Aging Effects Element - The GALL Report states, "Visual inspection by fire The environment to which inaccessible seals are exposed is very similar, if not the protection qualified inspectors of approximately 10% of each type of seal in walkdowns same, as the environment for accessible seals such that the condition of accessible is performed at least once every refueling cycle." The LRA states, "The NUREG-1801 seals is representative of the condition of inaccessible seals.

program states that 10% of each type of penetration seal should be visually inspected The LRA was amended to remove the word "accessible". TRM 4.13.E.1 provides the at least once every refueling outage. The VYNPS program specifies inspection of surveillance requirement for all vital fire barrier penetration seals.

approximately 25% of the seals (regardless of seal type) each operating cycle, with all accessible fire barrier penetration seals being inspected at least once every four (4) operating cycles. Since aging effects are typically manifested over several years, this variation in inspection frequency is insignificant." How are inaccessible seals addressed?

35 B.1.12.1-L-06 LR Commitment 8 Acceptance Criteria Element - The GALL states, "Inspection results are acceptable if there are no visual indications (outside those allowed by approved penetration seal License Renewal Commitment 8 addresses the need to revise these acceptance configurations) of cracking, separation of seals from walls and components, separation criteria.

of layers of material, or ruptures or punctures of seals; no visual indications of concrete Any recordable indication is entered into the Corrective Action Program for cracking, spalling and loss of material of fire barrier walls, ceilings, and floors; no visual evaluation.

indications of missing parts, holes, and wear and no deficiencies in the functional tests of fire doors." The LRA states, "Acceptance criteria will be enhanced to verify no significant corrosion." How much corrosion is considered "significant?" What actions are taken, either with or without "significant corrosion"? Is there a VYNPS commitment number associated with this enhancement?

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Item Reauest Response Item RauestResDonse 36 B.1.12.2-L-01 No, VYNPS does not have fire water storage tanks. Reference UFSAR Section Program Description Item - The GALL states, "This aging management program (AMP) 10.11.

applies to water-based fire protection systems that consist of sprinklers, nozzles, fittings, valves, hydrants, hose stations, standpipes, water storage tanks, and aboveground and underground piping and components that are tested in accordance with the applicable National Fire Protection Association (NFPA) codes and standards."

The LRA states, "This aging management program applies to water-based fire protection systems that consist of sprinklers, nozzles, fittings, valves, hydrants, hose stations, standpipes, and aboveground and underground piping and components that are tested in accordance with applicable National Fire Protection Association (NFPA) codes and standards." Does VYNPS have fire water storage tanks?

37 B.1.12.2-L-02 LR-Commitment 11 Program Description Item - The GALL states, "The fire protection system piping is to be subjected to required flow testing in accordance with guidance in NFPA 25 to verify This paragraph comes from NUREG-1 801,Section XI.M27 program description.

design pressure or evaluated for wall thickness (e.g., non-intrusive volumetric testing or The recommendation for flow testing is included in the NUREG-1801 technical basis plant maintenance visual inspections) to ensure that aging effects are managed and for the parameters monitored/inspected attribute. As stated in LRA Section that wall thickness is within acceptable limits. These inspections are performed before B.1.12.2, the VYNPS Fire Water System Program is consistent with this attribute.

the end of the current operating term and at plant-specific intervals thereafter during the Every fire main segment is full flow tested using the guidelines of NFPA 25 at least period of extended operation. The plant-specific inspection intervals are to be once every 3 years. Reference LRPD-02 (AMPER) Section 4.12.2.

determined by engineering evaluation of the fire protection piping to ensure that degradation will be detected before the loss of intended function. The purpose of the full The recommendation for wall thinning monitoring is included in the NUREG-1801 flow testing and wall thickness evaluations is to ensure that corrosion, MIC, or bio- technical basis for the detection of aging effects attribute. As indicated in LRA fouling is managed such that the system function is maintained." The LRA does not Section B.1.12.2, the Fire Water System program includes an enhancement to this address this item. How does VYNPS intend to address these NFPA and GALL attribute to perform wall thickness evaluations of fire protection piping using non-recommendations? intrusive techniques (e.g., volumetric testing) to identify evidence of loss of material due to corrosion. These inspections will be performed before the end of the current operating term and at intervals thereafter. Results of the initial evaluations will be used to determine the appropriate inspection interval.

38 B.1.12.2-L-03 LRA Amendment Detection of Aging Effects Element - The GALL Report states, "Fire hydrant hose LR Commitment 49 hydrostatic tests, gasket inspections, and fire hydrant flow tests, performed annually, ensure that fire hydrants can perform their intended function and provide opportunities The first paragraph for the detection of aging effects exception in LRA Section for degradation to be detected before a loss of intended function can occur." The LRA B.1.12.2 is hereby revised as follows. License Renewal Commitment 2 specifies states, "NUREG -1801 specifies annual fire hydrant hose hydrostatic tests. Under the that fire hydrant hoses will be tested, inspected and replaced if necessary, in VYNPS program, hydrostatic test of outside hoses occurs once per 24 months; and accordance with NFPA standards.

hydrostatic test of inside hoses occurs once per 3 years." Provide justification for relaxing the test frequency. NUREG-1801 Program XI.M27 specifies annual fire hydrant hose hydrostatic tests.

Fire hydrant hoses are consumables and therefore, not subject to aging management review. Since they are not subject to aging management review, fire hydrant hoses are not included in the VYNPS Fire Water System Program.

Also, the following exception note is added.

2. Per NUREG-1800, Table 2.1-3, fire hydrant hoses are consumables not subject to aging management review. During the period of extended operation, fire hydrant hoses will be tested, inspected and replaced, if necessary, in accordance with NFPA standards.

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Item Request ResDonse 39 B.1.12.2-L-04 LR Commitment 31 and 49 Detection of Aging Effects Element - The GALL states, "Fire hydrant hose hydrostatic LRA Amendment tests, gasket inspections, and fire hydrant flow tests, performed annually, ensure that fire hydrants can perform their intended function and provide opportunities for Since aging effects are typically manifested over several years, differences in degradation to be detected beiore a loss of intended function can occur." The LRA inspection and testing frequencies are insignificant. The review of operating states, "NUREG-1 801 specifies annual gasket inspections. Under the VYNPS program, experience did not reveal age-related failures of fire water system components that visual inspection, re-racking and replacement of gaskets in couplings is to occur at led to loss of intended function. Reference LRA Section B.1.12.2, exception note 1 least once per 18 months." Provide justification for relaxing the test frequency. and LRPD-05 (OE Report). License Renewal Commitment 31 agrees to examine these components annually and Commitment 49 is provided to ensure that station procedures specify testing, inspection and replacement when necessary in accordance with NFPA code specifications for fire hydrant hoses.

40 B.1.12.2-L-05 LR Commitment 31 and 49 Detection of Aging Effects Element - The GALL states, "Fire hydrant hose hydrostatic LRA Amendment tests, gasket inspections, and fire hydrant flow tests, performed annually, ensure that fire hydrants can perform their intended function and provide opportunities for As stated in LRA Section B.1.12.2, exception note 1, since aging effects are degradation to be detected before a loss of intended function can occur." The LRA typically manifested over several years, differences in inspection and testing states, "NUREG-1801 specifies annual fire hydrant flow tests. Under the VYNPS frequencies are insignificant. The review of operating experience did not reveal age-program, verification of operability and no flow blockage occurs at least once every 3 related failures of fire water system components that led to loss of intended years." Provide justification for relaxing the test frequency. function. Reference LRPD-05 (OE Report).

License Renewal Commitment 31 agrees to examine these components annually and Commitment 49 is provided to ensure that station procedures specify testing, inspection and replacement when necessary in accordance with NFPA code specifications for fire hydrant hoses.

41 B.1.12.2-L-06 LR Commitment 11 Detection of Aging Effects Element - The GALL Report states, "Fire protection system testing is performed to assure that the system functions by maintaining required License Renewal Commitment #11 is the commitment associated with this operating pressures. Wall thickness evaluations of fire protection piping are performed enhancement.

on system components using non-intrusive techniques (e.g., volumetric testing) to identify evidence of loss of material due to corrosion. These inspections are performed before the end of the current operating term and at plant-specific intervals thereafter during the period of extended operation." The VYNPS LRA identified the following enhancement, "Wall thickness evaluations of fire protection piping will be performed on system components using non-intrusive techniques (e.g., volumetric testing) to identify evidence of loss of material due to corrosion. These inspections will be performed before the end of the current operating term and at intervals thereafter during the period of extended operation. Results of the initial evaluations will be used to determine the appropriate inspection interval to ensure aging effects are identified prior to loss of intended function." What is the VYNPS commitment number associated with this enhancement?

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Item Request Response 42 B.1.15.1-W-01 Portions of drawings G-191150, G-191277, & G-191481 have been provided to the Provide drawings for the sand pocket region of the Drywell. Provide drawings for the NRC for the Sand pocket region of the Drywell; Refueling Bellows assemblies, and refueling bellows detailing how they are stored, installed, connected and sealed. the General Arrangement of the Reactor Building including the Primary Provide procedures for how the refueling bellows are used. Provide drawings of the Containment.

Drywell showing the gap and fill material between the secondary concrete shield wall from the refueling bellows/cavity seal connection down to the sand pocket region. The Refueling Bellows (to RPV) and the Drywell to Reactor Cavity Seal assemblies Provide the VYNPS response to Generic Letter 87-05. are permanently installed by full penetrant welds. The bellows allow the Refueling Cavity to be flooded during refueling operations to allow for spent fuel transfer to the Spent Fuel Pool for storage. No procedures are required for the operation of the bellow assemblies since they are static. Operation of the drain line isolation valves are controlled by plant operating procedures used for flood-up and drain-down of the cavity.

There is no fill material in the gap located between the Drywell Shell and the Secondary Concrete Shield.

VYNPS response to GL 87-05 has been provided to the NRC.

43 B.1.15.1-W-02 VYNPS has a Service Level I Coatings Program; however it is not relied on for It is stated in the VYNPS UFSAR that all interior and exterior drywell surfaces which are managing the aging effects for licensing renewal.

exposed to the atmosphere are protected from corrosion by application of a corrosion resistant coating material. However, in the VYNPS LRA it is stated that VYNPS does The VYNPS UFSAR states: "No material within primary containment will fail by not rely on protective coating to manage the effects of aging. The VYNPS LRA decomposition or corrosion and affect vital systems." The examination of the coated Appendix B does not have a Protective Coating Monitoring and Maintenance Program surfaces is performed as a part of the Containment Inservice Inspection Program section. However, there is a GALL AMP XI.S8 called Protective Coating Monitoring and (IWE) to assure that the paint and base metal has not degraded (TS Section 4.7.A).

Maintenance Program which states the following: Proper maintenance of protective, VY has an active and effective Service Level I Coatings Program to prevent coatings inside containment (defined as Service Level I) is essential to ensure degradation to the primary containment structure.

operability of post-accident safety systems that rely on water recycled through the containment sump/drain system. Explain why VYNPS does not have a Service Level I VYNPS response to GL 98-04 includes our commitment to EPRI TR-109937 Protective Coating Monitoring and Maintenance Program to prevent coating failure that "Guideline on Nuclear Safety-Related Coatings (renumbered 1003102). The GL could adversely affect the operation of post-accident fluid systems and thereby impair also discusses the impact of debris loading on the ECCS strainers. These strainers safe shutdown. Provide a copy of the VYNPS response to GL 98-04 and discuss if were designed to accept 100% of the coatings within the LOCA zone of influence.

VYNPS considers the maintenance programs described acceptable coatings AMPs for The approach velocity of materials entrained in the torus water is extremely low due license renewal. to the sizing of the ECCS strainers. Conservative design assumptions ensures VYNPS compliance with 10CFR50.46(b)(5).

A copy of VYNPS response to GL 98-04 has been provided.

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Item Request Response 44 B.1.15.1-W-03 Entergy chose to describe the Inservice Inspection and Containment Inservice Explain why the Containment Inservice Inspection Program is a plant-specific program Inspection Programs as plant-specific programs rather than comparing to the instead of an ASME Section Xl, subsection IWE program with exceptions. Explain why corresponding NUREG-1 801 programs because the NUREG-1801 programs contain the scope of the Containment Inservice Inspection Program does not include many ASME Section Xl table and section numbers that change with different containment seals, gaskets and pressure retaining bolts. Explain under what VYNPS versions of the code. Because of this, comparison with the NUREG-1801 programs AMPs the inspection of these components are performed. It is stated in the VYNPS generates many exceptions and explanations that detract from the objective of the LRA that the Containment Inservice Inspection Program is an existing program. comparison. VYNPS follows the version of ASME Section Xl that is approved for Explain if this program has been in compliance with ASME Section Xl, subsection IWE use at VYNPS and accepted by 10CFR50.55(a). As this is the case, the Inservice since the final rulemaking to require IWE inspections was made by the NRC in 1996. Inspection and Containment Inservice Inspection Programs are presented as plant-Provide a copy of the VYNPS notification of commitment to IWE inspections. specific programs so they can be judged on their own merit without the distraction of numerous explanations of code revision.

The Containment Inservice Inspection Program does not include containment seals or gaskets because they have been removed from the scope of Subsection IWE in the 1998 Edition of ASME Section Xl with 2000 Addenda. These components are inspected under the Structures Monitoring Program as indicated in Table 3.5.2.1 of the LRA. Pressure retaining bolts are considered and included as integral part of the structural components.

The Containment Inspection Program does not include containment seals or gaskets because they have been removed from the scope of Subsection IWE in the 1998 Edition of ASME Section Xl with 2000 Addenda. These components are seal tested under the Containment Leak Rate Program. Pressure retaining bolts are considered and included as Containment Inservice Inspection Program.

VY has been in compliance withlOCFR50.55a (b)(2)(vi) and (b)(2)(ix) since at least September 9, 2001. No notification of commitment to the IWE examinations was required by 10CFR50.55a. In 2003, VY submitted a notification of the intent to use ASME Section Xl -1998 Edition with 2000 Addenda as the Code of Record for all ISI programs. A copy of the submittal has been provided.

45 B.1.15.1-W-04 Examinations are performed in accordance with the Code of Record that requires Explain how inspections are performed in the torus suppression pool above and below the examination of all accessible interior and exterior surfaces. In 1998, the interior the waterline. Explain historically what inspection findings have lead to the need for surface, slightly above and fully below the water line, was stripped and coated.

augmented inspections. Explain if any augmented inspections are currently being During RFO-24 (2004), the Suppression Pool exterior surface was General Visual performed. The LRA states that VYNPS uses inspection program B for containment examined. Though normally inaccessible, the Suppression Pool interior was made inservice inspection. Provide the inspection interval dates through the current license accessible and the surface above the water-line was General Visual examined.

and also through a possible license extension period. During the General Visual examination of the interior surface, the water clarity permitted observation of nearly 100% of the submerged surface area. Three small areas (at the water line) in BAY 3 were identified to have a loss of coating and primer. These areas were UT (ultrasonic tested) from the exterior, in 2" gridded areas. No result approached the minimum wall thickness of 0.533" with the lowest reading being 0.597." Based on the results, these areas were excluded from augmented examination. In RFO-27 (2008), the VT-3 of the wetted areas is presently planned to be executed by divers without dewatering the Suppression Pool. The current examination schedule is contained in Program Bases Document (4.14,2) in the PP 7024 tables. The projected schedule through the possible license extension period will be developed in accordance with the Code in effect but should be 6 inspection periods in 20 years.

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Item Request Response 46 B.1.15.1-W-05 Drywell moisture barrier is examined under the Containment Inservice Inspection VYNPS lists several Containment Inservice Inspection findings under operating Program. Table IWE-2500-1 Item E1.30 of ASME Section XI-1 998 Edition with experience for AMP B.1.15.1 in the LRA. Explain why the operating experience 2000 Addenda is contained in the Program Bases Document (4.14.2) in the PP discusses the drywell moisture barrier when the inspection of it does not appear to be in 7024 tables. The Program Based Document (4.14.2) in Section B.1.15.1.10, the scope of the VYNPS Containment Inservice Inspection Program. Provide the describes the area examined and replaced during RFO-21 (2001). LRA Table documentation for any containment inspection findings from the most recent RFO if 3.5.2.6 shows the drywell moisture barrier to be inspected under the structural beyond 24. Explain if water leakage has ever been discovered between the drywell and monitoring program; this will be changed to the Containment Inservice Inspection concrete secondary shield wall or in the sand pocket area. Explain what VYNPS does Program. IWE examinations during RFO-25 (2005) produced no findings.

to inspect for water leakage in these two areas or to verify that loss of material is not occurring on the backside of the Drywell. Provide the documentation for the RFO 24 In 1991, an Auxiliary Operator (AO) observed water running from a crack in the issues identified by QA surveillance that are discussed in the operating experience. Drywell pedestal concrete onto the Torus Room floor. The investigation revealed Provide the latest engineering system health report for the containment in-service leakage from a steam valve was condensing on and traveling along the Primary inspection program. Containment Air Conditioning piping to the Drywell shell. From the Drywell shell, the water found a crack or cold-joint that directed it to the Torus Room floor. To ensure the Drywell shell integrity, the sand-cushion drains were examined and found to be functional; the exterior drywell shell was inspected and determined to be non-corroded; and the sand-cushion was observed to be dry, compacted, with adequate ventilation to assure the sand would remain dry.

47 B.1.16-P-1 LR Commitment 28 Please identify the standard(s) to which instrument air is maintained, and document this commitment in Appendix A if appropriate. License Renewal Commitment # 28 ensures that instrument air is maintained in accordance with ISA S7.3.

48 B.1.17-N-01 LRA Amendment GALL XI.E3 under "Detection of Aging Effects" recommends that the inspection for water collection should be performed based on actual plant experience with water LRA Appendix B.1.17 will be revised to include the following:

accumulation in the manhole. However, the inspection frequency should be at least VYNPS inspection for water accumulation in manholes is conducted by a plant once every two years. VYNPS AMP B.1.17 under the same attribute requires procedure. An engineering evaluation will be used per EN-LI-1 02 to document and inspection for water collection in cable manholes and conduit occurs at least once every determine the plant experience that is considered in manhole inspection frequency.

two years. Explain how actual plant experience is considered in the manhole inspection frequency to be consistent with GALL's XI.E3.

49 B.1.17-N-02 Operating Experience at VYNPS is controlled by procedure EN-OP-100, Operating In AMP B.1.17 under the "Operating Experience" element, you have stated that the Experience Program. The program includes the following components:

"Non-EQ Inaccessible Medium-Voltage Cable Program" at VYNPS is a new program for Operating Experience - Information received from various industry sources that which there is no operating experience. GALL XI.E3 under the same element states describe events, issues, equipment failures that may represent opportunities to that operating experience has shown that cross linked polyethylene (XLPE) or high apply lessons learned to avoid negative consequences or to recreate positive molecular weight polyethylene (HMWPE) insulation materials are most susceptible to experiences as applicable.

water tree formation. The formation and growth of water trees varies directly with Internal Operating Experience - Operating Experience that originates as a condition operating voltage. Water treeing is much less prevalent in 4kV cables than those report or request from plant personnel that warrants consideration for possible operated at 13 or 33kV. Also, minimizing exposure to moisture minimizes the potential Entergy-wide distribution. Internal OE can originate from any Entergy plant or for the development of water treeing. As additional operating experience is obtained, headquarters.

lessons learned can be used to adjust the program, as needed. NUREG-1 800, Rev. 1, Impact Evaluation - Analysis of an OE event or problem that requires additional Appendix A, Branch Technical Position RLSB-1 states that an applicant may have to information and research to determine impact or potential impact, as it relates to commit to providing operating experience in the future for new programs to confirm their plant condition and/or configuration. Impact evaluations are typically documented effectiveness. Describe how operating experience is captured at VYNPS to confirm with a Condition Report.

program effectiveness or how it is to be used to adjust the program as needed. Condition Report action items and corrective actions are used to confirm program effectiveness and to modify the program as needed.

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Item Request Response 50 B.1.17-N-03 LR Commitment 43 As stated in FSAR Section 8.3.3 (Page 8.3-5 of 8), the underground power lines - that run from the adjacent Vernon Hydroelectric Station to station switchgear - have been Yes, the underground power lines that run from Vernon Dam Switchyard to VYNPS designated as the Station Blackout alternate AC source. Thus; they are used to meet safety buses, are included in program B.1.17.

Station Blackout requirements 10 CFR 50.63. Are these cables included in the scope of AMP B.1.17? If not, provide an explanation. CLOSED TO RAI 3.6.2.2.N-08 51 B.1.18-N-01 LRA Amendment In AMP B.1.18, you have stated that for neutron flux monitoring system cables that are disconnected during instrument calibration, testing is performed at least once every 10 LRA Appendix B.1.18 will be revised as follows:

years . GALL XI.E2 recommends that the test frequency shall be determined by the The first test of neutron monitoring system cables that are disconnected during applicant based on engineering evaluation, but the test frequency shall be at least once instrument calibrations shall be completed before the period of extended operation every ten years. Explain how engineering evaluation is considered in the test and subsequent tests will occur at least every 10 years. In accordance with the frequency; in order to be consistent with GALL XI.E2. Corrective Action Program, an engineering evaluation will be performed when test acceptance criteria are not met and corrective actions, including modified inspection frequency will be implemented to ensure that the intended functions of the cables can be maintained consistent with the current licensing basis for the period of extended operation.

52 B.1.18-N-02 Yes, the B.1.18 program includes both cables and connections for the instrument Confirm that the test includes both cables and connections. circuits that are in scope for license renewal.

53 B.1.19-N-01 LRA Amendment In AMP B.1.19 you have stated that the a representative sample of accessible insulated cables and connections, within the scope of license renewal, will be visually inspected The LRA Appendix B.1.19 program description will be changed to read as follows:

for cable and connection jacket surface anomalies such as embrittlement, discoloration, This program addresses cables and connections at plants whose configuration is cracking or surface contamination. The technical basis for sampling will be determined such that most cables and connections installed in adverse localized environments using EPRI document TR-1 09619, "Guideline for the Management of Adverse Localized are accessible. This program can be thought of as a sampling program. Selected Equipment Environments". Explain the technical basis for cable sampling. cables and connections from accessible areas will be inspected and represent, with reasonable assurance, all cables and connections in the adverse localized environments. If an unacceptable condition or situation is identified for a cable or connection in the inspection sample, a determination will be made as to whether the same condition or situation is applicable to other accessible cables or connections.

The sample size will be increased based on an evaluation per EN-LI-102 -

Corrective Action Process.

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Item Reauest Response 54 B1.19-N-02 Operating Experience at VYNPS is controlled by procedure EN-OE-100, Operating In AMP B.1.19 under the "Operating Experience" element, you have stated that the Non- Experience Program. The program includes the following components:

EQ Insulated Cables and Connection Program at VYNPS is a new program for which *Operating Experience - Information received from various industry sources that there is no operating experience. GALL XI.E1 under same element states that describe events, issues, equipment failures, that may represent opportunities to operating experience has shown that adverse localized environments caused by heat or apply lessons leamed to avoid negative consequences or to recreate positive radiation for electrical cables and connections may exist next to or above (within three experiences as applicable.

feet of) steam generators, pressurizers or hot process pipes, such as feedwater lines. -internal Operating Experience - Operating Experience that originates as a These adverse localized environments have been found to cause degradation of the Condition Report or request from plant personnel that warrants consideration for insulating materials on electrical cables and connections that is visually observable, Entergy-wide distribution. Internal OE can originate from any Entergy plant or such as color changes or surface cracking. NUREG-1800, Rev. 1, Appendix A, Branch headquarters.

Technical Position RLSB-1 under operating experience states that an applicant may -impact Evaluation - Analysis of an OE event or problem that requires additional have to commit to providing operating experience in the future for a new program to information and research to determine impact or potential impact, as it relates to confirm its effectiveness. Describe how operating experience will be captured by plant condition and/or configuration. Impact evaluations are typically documented VYNPS. within a Condition Report.

Condition Report action items and corrective actions are used to confirm program effectiveness and to modify the program as needed.

55 B.1.20-K-01 As stated in LRA Section B.1.20, exception note 1, flash point is not determined for For those components that do not have regular oil changes, please provide the basis sampled oil because analyses of filter residue or particle count, viscosity, total for Note 1 (not determining the flash point for the sampled oil). acid/base (neutralization number), water content, and metals content provide sufficient information to verify the oil does not contain water or contaminants that would permit the onset of aging effects.

Added Response: Fuel dilution is measured on EDG lube oil, rather than determiming the flash point.

In lieu of performing Flash point testing on the Emergency Diesel Generators, Diesel Driven Fire Pump and the John Deere Diesel Generator, a test for fuel and water by

% of volume is performed. This test accomplishes the same goal as the flash point test but is more prescriptive then the flash point test. There could be two factors that affect the flash point of the oil; the addition of fuel that would lower the flash point or the addition of water that would raise the flash point. The worst case would be a combination of the two. By determining the % by volume of both fuel and water, the analysis can determine the cause of the change in flash point without having to conduct additional tests and corrective actions, if required, could be implemented on a timelier basis.

Additional tests to determine the "Health" of the diesels are; total base number (TBN), viscosity, SAE Grade, Total Soot, and Spectrometals analysis (for wear metals and additives). The results of these analyses are trended to determine the total health of the diesel and the quality of its lubricating oil. Diesel Lube Oil Analyses are performed on a quarterly basis.

56 B.1.20-K-02 As indicated in LRA Section B.1.20, the Oil Analysis Program is consistent with How are the alert levels or action limits established? How is the data trended and what NUREG-1 801,Section XI.M39 for the acceptance criteria attribute. As criteria are used to determine if the trends are unusual? recommended in NUREG-1801, action limits were established in accordance with industry standard ISO 4406 and manufacturer's recommendations. See DP 0213 (available for on-site review in the program basis document) for trending and criteria.

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Item Request Response 57 B.1.21-K-01 Attachment 2 of LRPD-02 (AMPER), which is available for on-site review in the Please provide a table outlining the inspection methods used for each aging effect and program basis document, is a table similar to the table provided in the GALL report.

parameter monitored or inspected. This should be consistent with the table provided in Attachment 2 identifies the inspection method and parameters monitored for GALL Report AMP XI.M32. If not, provide a justification for any exceptions to this table. applicable aging effects. As indicated in LRA Section B.1.21, Attachment 2 of LRPD-02 (AMPER) is consistent with the table provided in NUREG-1 801,Section XI.M32.

58 B.1.21-K-02 Combinations of non-destructive examinations including visual, ultrasonic, and The table provided in the program description in section B.1.21 indicates that the one- surface techniques will monitor cracking of CASS valve bodies in piping <4" NPS to time inspection activity will confirm that the loss of fracture toughness is not occurring confirm that reduction of fracture toughness is not occurring or is so insignificant or is so insignificant that an aging management program is not warranted. What that an aging management program is not warranted. Reference Attachment 2 of inspection method is used to detect this aging effect and what parameter is monitored? LRPD-02 (AMPER).

Please address the main steam flow restrictors in the response.. Main steam flow restrictors:

Thermal aging embrittlement results in increased rates of crack growth that are evidenced by cracking in the material. The One-Time Inspection Program will be used to verify that reduction of fracture toughness has not progressed to the point that unacceptable cracking of the component has occurred.

59 B.1.21-K-03 The review of plant operating experience (1998 to 2005) did not reveal instances of What is Vermont Yankee's operating experience with Class 1 piping less than 4 inches cracking of Class I piping less than 4"NPS. Site to confirm and address experience NPS in terms of cracking? prior to 1998.

-In the early years of plant operation VYNPS experienced occurrences of intergranular stress corrosion cracking (IGSCC) in some stainless steel piping systems. In the period of approximately 1980 through 1986 VYNPS embarked on a major IGSCC mitigation program, replacing the susceptible stainless steel piping with IGSCC resistant materials. Since then, there have been no instances of IGSCC or other pipe cracking events at VYNPS. See report "YAEC-1 247, Rev. 1'" and Letter FVY 88-62.

60 B.1.22-M-01 This information is included in Attachment 3 of LRPD-02 (AMPER) that is available As stated by the applicant, "...prior to the period of extended operation, program activity for on-site review in the program basis document.

implementing documents will be enhanced as necessary to assure that the effects of aging will be managed...." The applicant is asked to provide a listing of which specific PSPM plant implementing documents will be enhanced and why such an enhancement is necessary for each implementing document.

61 B.1.22-M-02 Yes. Reference LRA Table B-2 and Section B.1.22 Program Description.

In the statement for the "operating experience" element of the AMP, the applicant, notes that "...the material condition of cranes was consistent with inspection acceptance criteria..", and "...ECCS corner room recirculation units had no significant corrosion..". By the appearance of these statements in the "operating experience" of the PSPM, is the staff to understand that the applicant intends to use the applicant's PSPM AMP in lieu of the GALL-recommended programs - XI.M23, "Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems", and XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components"- during the period of extended operation?

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Item Request Response 62 B.1.23-M-01 VYNPS meets the 1998 edition through 2000 addenda of the ASME Section XI As noted in the GALL, [Section XIM3, Element Number four (4) - "Detection of Aging Code, Sub Section IWB 2500-1 Examination Category B -G-1 ."Pressure Retaining Effects"]; GALL-recommended programs use visual, surface, and volumetric Boiler Greater than 2" in Diameter" items BG.20 and .30 that specifies a surface or examinations, to indicate the presence of surface discontinuities/flaws and other volumetric examination method.

discontinuities/flaws throughout the volume of material. The applicant's proposed exception states that cracking initiates on the outside surfaces of the bolts/studs, and by meeting acceptance standards of IWB-3515, this "surface-type" examination will

"...provide at least the sensitivity of flaw detection that an end shot ultrasonic examination provides on bolts/studs...". The applicant is asked to provide further evidence that such a "qualified surface examination" provides the stated level of sensitivity with the thoroughness of other GALL-recommended programs.

63 B.1.23-M-02 As stated in LRA Section B.1.23, the Reactor Head Closure Studs Program is Some replacement stud bolts use a manganese phosphate surface treatment in consistent with NUREG-1 801, XI.M3 for the preventive actions attribute. As combination MoS2 to prevent bolt degradation due to corrosion or hydrogen described in NUREG-1801, threaded surfaces of studs, nuts and washers have a embrittlement. The applicant's AMP notes that Vermont Yankee's existing program phosphate coating to act as a rust inhibitor and lubricant. Also, a stable lubricant includes preventive measures, such as "appropriate materials", to mitigate cracking and compatible with the bolting and vessel materials is applied to the stud threads, the loss of material. GALL Section XI.M3, [Element Number two (2) - "Preventive Actions"] mating surfaces of the washers and the nut threads during assembly. Reference states that the use of this type of surface treatment is acceptable and effective. Does LRPD-02 (AMPER) Section 4.18.

the applicant use similar bolting with a similar type of surface treatment?

64 B.1.23-M-03 The 2002 examinations included visual and ultrasonic inspections. The 2004 As noted in GALL,Section XI.M3, [Element Number ten (10) - "Operating Experience"]; examinations were visual only as per the stated exception. Future examination will GALL-recommended programs should have provisions regarding inspection techniques be visual only in accordance with ASME Code Case N-652. Code Case N-652 has and evaluation.. The applicant states, in its explanation of their existing program, that been endorsed by the NRC per Table 1 of Regulatory Guide 1.147. Revision 14.

"...recent (2002 and 2004) visual and ultrasonic inspections.. .revealed no recordable indications..". The applicant is asked to compare examinations performed in 2002 and 2004 with the "exception-stated" examination technique proposed for future examinations and to provide to the staff the results of this comparison.

65 B.1.26-W-01 Procedures OP 5265, Service Water Component Inspection and Acceptance Provide examples of VYNPS plant procedures used to implement the requirements of Criteria; PP 7021, Service Water Program; and PP 7601, Service Water Chemical GL 89-13/Service Water Integrity AMP for routine inspection and maintenance of the Treatment and Monitoring Program are available for on-site review in the program service water systems. Include examples of actual visual and NDE testing. Explain basis document.

any differences between the GL 89-13 program scope and the Service Water Integrity Program scope for license renewal. As stated in LRA Section B.1.26, the Service Water Integrity Program is consistent with NUREG-1 801, XI.M20 for the scope of program attribute. Therefore, there are no differences between the GL 89-13 program scope and the Service Water Integrity Program scope for license renewal.

66 B.1.26-W-02 Provided a copy of the original site piping specification OC-10 that shows the piping Provide the original (or current if pipe has been replaced) material and lining for the Service Water and alternate cooling water systems piping is carbon steel specification for the buried piping which is part of the service water system, including material and are not coated.

the alternate cooling system.

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Item Reauest ResDonse 67 B.1.26-W-03 Linings and coatings are not credited. Piping that is lined or coated will be inspected

VYNPS takes exception to GALL AMP XI.M20 element 2 by stating that not all VYNPS with the same techniques used for unlined piping. An itemized listing of which service water system components are lined or coated. Components are lined or coated piping is lined or coated was not necessary for the aging management review.

only where necessary to protect the underlying metal surfaces. Provide an itemized list of the piping in the service water system where it is lined or coated to protect the In accordance with the piping specification QC-10 there is no coated piping in the underlying metal surfaces. Provide the type of lining or coating for each item on the list. Service Water system. The only coated components are a few valve body internals and heat exchanger heads that are currently and will continue to be inspected as part of the Service Water program.

68 B. 1.26-W-04 The only sections of the Service Water (SW) system that are flushed on a regular Explain if there any portions of the service water system that are infrequently used and basis are the instrumentation tubing lines (3/8" stainless steel tubing). A list of the are periodically flushed. If so, describe these portions and how often they are flushed. specific lines has been provided. These lines are flushed on a 12 or 18 month basis Explain the criteria used to initiate the flushing. Explain if any other flushing of the as identified in the Preventive Maintenance program. The SW strainers are self system is done and how the strainers are cleaned. Discuss the historic inspection cleaning and are not opened and cleaned on a regular basis. The suction line from results of the gravity portion of the ACS piping coming from the deep water basin and if the deep basin to the RHRSW pumps is opened and inspected every other outage this has been a problem area with flow blockage. (3 years). The results of the inspection have shown the line to be free of tuberlication and silt. The line is treated with a biocide before being closed after inspection. No issues with flow blockage have been identified in the past six years.

The line was found to be fouled in the early 1990's and was subsequently cleaned and the addition of biocide was started. This appears to be very successful based on the recent inspections.

69 B.1.26-W-05 PP7021 provides information related to VYNPS's compliance with GL89-13 VYNPS takes exception to GALL AMP XI.M20 element 5 by stating that the VYNPS requirements. A copy of this procedure was provided. GL 89-13 provides for the program requires tests and inspections each refueling outage, but not annually. options of performing either thermal performance testing or periodic cleaning.

Provide documentation that this frequency is in agreement with the commitments made VYNPS has chosen to perform cleaning for most of the SW supplied heat by VYNPS under GL 89-13. Provide the frequency of heat transfer testing for each exchanger and coolers. The exceptions are the Stand-by Fuel Pool Cooling heat exchanger in the service water system. The applicant is requested to state which (SBFPC) Heat Exchangers, the Emergency Diesel Generator Coolers (3 each) and VYNPS group is responsible for reviewing the test data and to provide through a plant the Corner Room RRU's #7 & 8. The SBFPC heat exchangers are thermal procedure an example of how this process is implemented. Explain the type of heat performance tested every 18 months. Based on the satisfactory results of the tests transfer testing'which is done on the service water system heat exchangers. VYNPS is preparing a change to perform cleaning instead of testing. The coolers have been internally examined and found to be very clean and free for silt, sludge and tuberculation. The frequency of cleaning has yet to be determined but is anticipated to be in the every 3 to 6 year range. The Emergency Diesel Generator Coolers are tested every month and the results are trended by System Engineering.

No adverse trends have been identified. A copy of the trends for the "B" Diesel has been provided. Copies of the test data sheets for the entire year 2004 have been provided.. The RRU's are tested quarterly by measuring the DP across the units.

This will detect any fouling which would decrease thermal performance. No performance issues have been identified. All performance data and Inspection results are monitored and trended by the System Engineering Department and the Service Water System Engineer.

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Item Request Response 70 B.1.26-W-06 A copy of NRC Report, NVY 02-61 and CR-VTY-2003-02344 was provided. This CR Provide the NRC inspection report written in 2002 for the service water system. documents the investigation into the adverse trend created by approximately 20 Characterize the 20 service water system leaks and how they were repaired under the through wall leaks in the SW system. The result of this investigation identified VYNPS corrective action program. Provide the VYNPS self-assessment and several causes. One of these being the use of carbon steel components which are independent evaluation which was completed on 12/20/2002. Provide an example of susceptible to Microbiological Influenced Corrosion (MIC). Another cause was the documents which provide the protocols for the use of biocides to mitigate MIC and determined to be ineffective chemical treatment of the system. The ineffectiveness any other procedure changes made after the self-assessment. Provide a sampling of of the chemical treatment was reinforced by a follow up assessment (DR Lutey the different performance testing and inspection results for 2004 that are discussed in Report). This assessment was also provided. Changes were made to the sampling the LRA operating experience with acceptance criteria. If more recent performance program and chemical treatment process. New chemical addition pumps were testing and inspection results are available, provide a sampling of them. installed and sampling was implemented for SW components during inspections. It should be noted that the plant is limited by the NPDES permit to no more than 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months a day of treatment to the SW system. This reduces the effectiveness of the treatments. VYNPS also began treatment of lines which are not normally inservice, i.e. supply line to the Diesel Generator Cooler. These lines are treated when the diesels are run to ensure that the lines are full of treated water when they are secured. Copies of the inspection database detailing the results of internal inspections have been provided.

71 B.1.26-W-06 Duplicate entry. Close to # 70.

Provide the NRC inspection report written in 2002 for the service water system.

Characterize the 20 service water system leaks and how they were repaired under the VYNPS corrective action program. Provide the VYNPS self-assessment and independent evaluation which was completed on 12/20/2002. Provide an example of the documents which provide the protocols for the use of biocides to mitigate MIC and any other procedure changes made after the self-assessment. Provide a sampling of thedifferent performance testing and inspection results for 2004 that are discussed in the LRA operating experience with acceptance criteria. If more recent performance testing and inspection results are available, provide a sampling of them.

72 B.1.27.1-W-01 Inspection Report for Masonry wall G-191513-51 provided in Drawing B-191600 Provide a masonry wall inspection report for an un-reinforced masonry wall. Sheet 96 for an un-reinforced masonry wall was provided.

73 B.1.27.1 -W-02 Site procedure PP-7026 will be in the program basis document Explain how often masonry walls are inspected for cracking. Explain ifthe inspection Additional Response:

frequency varies from wall to wall. If the frequency does vary, explain the basis for the Inspection of masonry walls, in scope of license renewal, are performed each differences in frequency. Explain the qualification and training that is required of the refueling outage. Upon completion of six successive surveillance intervals during a inspection personnel. Explain if inspectors use crack maps during the inspections to ten year period, the sequence of the inspection is reverted back to the initial help in the detection of changes. sequence interval. The inspections are performed by inspection team comprised of degreed engineers having understanding of structures, materials of masonry construction and masonry wall analysis techniques. The observed instances of cracking are detailed on as-built and considered in record analysis.

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Item Request Response 74 B. 1.27.1 -W-03 PP 7026 Rev 1 requires that if during the course of inspection, a "significant finding" Explain if Masonry Wall crack changes are turned over to engineering for evaluation is encountered a Condition Report shall be generated and the Civil Structural and documentation by procedure. Provide the procedure for performing the Masonry Supervisor is notified (Section 4.4, PP 7026). PP 7026 is provided for reference.

Wall crack inspections. What engineering procedures are used to control and evaluate The Engineering Request process is used to control the plants configuration. Walls the attachment of new components to masonry walls evaluated under NRC IEB 80-11 ? affected via planned modifications are identified during the design process and the Explain if there is a masonry wall log book or data base to track-new attachments to analysis of record and design drawings reflecting I. E. B. 80-11 are updated block walls and evaluate the effects on the existing evaluations performed under 80-11 ? accordingly. Administrative controls require that proposed new attachments are reviewed by the Civil Structural Department (Section 4.4.5, PP 7026). A log book is maintained by the Civil Structural Department with a summary findings memo and surveillance walkdown sheets (Form VYPPF 7026.01 and Section 4.4.7, PP 7026).

Attachments include the Vermont Yankee Masonry Wall Routine Surveillance for RFO 25 in which three corrective updates were performed for observed discrepancies. The CR generated for correcting the drawings is also attached along with a corrected drawing for example.

Entergy has now developed a fleet wide procedure for condition monitoring of maintenance rule structures (ENN-DC-150). The new procedure (applicable to VYNPS) has provisions which are much more detailed in the areas of walkdown documentation, record keeping and trending of results than what was in the VYNPS procedure PP7030. The new procedure enhances the VYNPS structures monitoring program relative to areas identified in the question.

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Item Request ResDonse 75 B.1.27.2-W-01 The water-control structure at VYNPS is the intake structure. There are no earthen The program description in the LRA for the Structures Monitoring Program (B.1 .27.2) water control structures at VYNPS. The attributes of the Water Control Structures, makes no reference to GALL,Section XI.S7, RG 1.127, Inspection of Water-Control GALL XI.S7 aging management program applicable to the intake structure are Structures Associated With Nuclear Power Plants. GALL XI.S7 states that for plants incorporated in the VYNPS Structures Monitoring Program as described below.

not committed to RG 1.127, Revision 1, aging management of water-control structures Attributes of the GALL XI.S7 aging management program that are not incorporated may be included in the Structures Monitoring Program. However, details pertaining to in the Structures Monitoring Program primarily apply to earthen structures.

water-control structures are to incorporate the attributes of GALL XI.S7. Explain if VYNPS is committed to RG 1.127 Revision 1 for inspection of its water control 1) Scope - The scope of the GALL XI.S7 program applicable to VYNPS is the intake structures (such as Intake Structure). If VYNPS is not committed to RG 1.127 Revision structure. The intake structure is included in the scope of the Structures Monitoring 1, explain how the 10 element attributes of GALL XI.S7 are incorporated into the Program as delineated in Table 3.5.2-3.

VYNPS Structures Monitoring Program.

2) Preventive actions - The GALL XI.S7 program includes no preventive actions.

3) Parameters Monitored - The aging effect requiring management for concrete structural components of the intake structure is loss of material which is consistent with GALL Volume 2 item lI.A6-7. The parameters monitored from the GALL XI.S7 program applicable to loss of material are consistent with those monitored by the Structures Monitoring Program. The guidance for inspections of concrete in Section C.2 of RG 1.127 is consistent with the guidance in ACI 349.3 used in the Structures Monitoring Program.

4) Detection of Aging - GALL XI.S7 identifies visual inspection methods as the primary method used to detect aging. The Structures Monitoring similarly uses visual inspection methods as the primary method used to detect aging in concrete structural components. GALL XI.S7 identifies inspection intervals of five years. The Structures Monitoring Program identifies similar inspection intervals of three years for accessible areas, ten years for inaccessible areas and opportunistic inspections for buried components.

5) Monitoring and Trending - Monitoring is by periodic inspection for both the GALL XI.S7 and Structures Monitoring Programs.

6) Acceptance Criteria - Acceptance criteria is not identified in RG 1.127, however appropriate guidance is provided in the Structures Monitoring Program to ensure corrective measures are identified prior to loss of intended function.

7-9) The corrective actions, confirmation process and administrative control attributes of the Structures Monitoring Program and the GALL XI.S7 program are consistent.

10) Operating Experience - The operating experience relevant to the effectiveness of the Structures Monitoring Program is presented in Appendix B of the application and is consistent with the operating experience described in GALL XI.S7.

Therefore, the attributes of the NUREG-1 801 XI.S7, Water Control Structures, aging management program pertaining to the intake structure are incorporated within the VYNPS Structures Monitoring Program.

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Item Reauest ResDonse 76 B.1.27.2-W-02 LRA Amendment Explain why the drywell floor liner seal and other components are not part of the ASME Section Xl subsection IWE inspection program. Justify this exclusion. Explain why the The drywell floor liner seal (moisture barrier) is examined under the Containment inspection of crane rails and girders are not under an Inspection of Overhead Heavy tnservice tnspection-IWE Program and will remain under the Clt-IWE Program Load and Light Load Handling Systems AMP. Explain if all the structures and during the period of extended operation not the Structures Monitoring Program as components being added to the Scope of Program for this AMP by enhancement are shown in LRA Table 3.5.2-1. This approach will require the following.

currently inspected by another program, since the SMP is an existing program. 1) Update LRPD-02, Section 4.14.2 Item B.4 by adding "The CII Program manages cracking and change in material properties for drywell shell to floor seal (moisture barrier) elastomers"

2) Update LRPD 02, Section 4.21.1 Items B.1.a and b "Enhancement" and Item 10.D. "Summary" to delete "drywell floor liner seal" from the discussion.

3) Update LRA Table Line Item "Drywell floor liner seal" for Table item "AMP" change "Structures Monitoring" to "CII-IWE". For clarification, change "drywell floor liner seal" to "drywell shell to floor seal (moisture barrier)" The clarification of the terminology also applies to Table 2.4-1 and Section B.1.27.2. (This change requires an amendment letter to the LRA)

The Periodic Surveillance and Preventive Maintenance and Structures Monitoring Programs adequately manage aging effects for cranes and girders. Therefore, a separate program (i.e., inspection of overhead heavy load and light load handling system) is not necessary. Not all the miscellaneous structures and components added by the enhancement to the SMP are currently inspected under another program.

77 B.1.27.2-W-03 LR Commitment 33 Explain if VYNPS has any porous concrete sub foundations and a site dewatering LRA Amendment system. Explain if the Structures Monitoring Program requires periodic sampling and testing of groundwater to determine and confirm that that the below grade water VNPS does not have porous concrete sub foundations or a site dewatering system.

chemistry/soil is non-aggressive to concrete structures below grade. Provide the The inspection team was provided with the results of the two most recent reported results for the two most recent tests and provide the scheduled frequency of groundwater samples as submitted to the State of Vermont. These samples are groundwater monitoring. Explain if there is any seasonal consideration for groundwater currently obtained twice yearly, primarily around the plant septic systems (some of monitoring. the sampling wells are near plant structures). The results of these samples are provided to the State of Vermont in accordance with our Indirect Discharge Permit.

The Structures Monitoring Program will be enhanced, (License Renewal Commitment #33) to ensure an engineering evaluation is made on a periodic basis (at least once every five years) of groundwater samples to assess for evidence of groundwater being aggressive to concrete. Historically, VYNPS groundwater samples have shown some level of seasonality in that the wells adjacent to roadways have slightly higher levels of chlorides due to salt treatment.

78 B.1.27.2-W-04 Yes. VYNPS will and currently does take advantage of inspection opportunities for Will VYNPS take advantage of inspection opportunities for structures required for underground structures that become accessible by excavation. This inspection is license renewal and identified as inaccessible? As inaccessible areas become already part of the program.

accessible by such means as excavation or other reason, will additional inspections of those areas be performed?

2r~~

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Item Request Response 79 B.1.27.2-W-05 Vermont Yankee's current structures monitoring program is performed by Design Explain how the frequency of inspection for the structures, buildings and components Structural Engineers in accordance with PP 7030, Structures Monitoring Program within the scope of this program are affected when aging effects are discovered. Procedure. Our surveillance tracking program ensures that this inspection is performed on a three year interval.

Any adverse condition discovered during inspections of buildings, structures and components would be entered into Entergy's Corrective Action Process through the initiation of a Condition Report in the PCRS tracking system. The Corrective Action Program defines further responses to the discovered condition. Attributes considered through the corrective action will include, as applicable, apparent cause evaluation, root cause evaluation, extent of condition, consideration of Operating Experience, required corrective action and follow-up verification. Frequency of future inspections will also be considered through the Corrective Action Process.

80 B.1.27.2-W-06 The VYNPS Structures Monitoring Program is controlled by PP 7030, Structures Explain if the inspection acceptance criteria for the Structures Monitoring Program is Monitoring Program Procedure. The standards used to develop and conduct the based on ACI 349.3R-96, and if not, provide the industry codes, standards and program are listed in Sect. 5.2 of the procedure. The specific standard used to guidelines that the acceptance criteria is based on. Explain the basis of the acceptance develop inspection requirements for this procedure is NEI 96-03, "Nuclear Energy criteria for crane rail/girder inspections and drywell floor liner seal. Institute, Industry Guideline for Monitoring the Condition of Structures at Nuclear Power Plants", Section 3.3 "Examination Guidance." Inspection requirements of commodities taken from NEI-96-03 are delineated in Section 4.3.3 of PP7030. A comparison of the relevant guidelines for concrete structural components in PP7030, with the guidelines of ACI 349.3 Chapter 5 "Evaluation Criteria" indicates general consistency.

1) Both documents specify visual inspection methods for the examination of structures.

2) Both documents provide guidance for the inspections for the following parameters and conditions:

Concrete components: spalling, cracking, delamination, honey combs, water in-leakage, chemical leaching, peeling paint, or discoloration Structure Settlement: excessive total or differential settlement Structural/seismic gap: insufficient space for structural movement during a seismic event (i.e., exclusion of foreign objects or debris); deteriorated elastomer type filler.

3) ACI 349.3R96 Chapter 5 provides acceptable limits beyond which further evaluation is required. PP7030 Section 4.8 conservatively requires evaluation of identified degradation.

Based upon this comparison, the guidance for inspections provided in PP7030 is consistent with the guidelines in ACI 349.3R96.

The acceptance criteria for crane rail/girder inspections are contained in the preventive maintenance tasks for the crane inspection. Procedure OP 2200 provides the inspection and acceptance criteria for crane rail/girders. The procedure criteria is based on the following codes and standards ANSI B30.2-83 "Overhead and Gantry Cranes" and NUREG-0612, Control of Heavy Loads at Nuclear Power Plants".

The acceptance criteria for the drywell shell to floor liner seal (moisture barrier) is covered under 4.14.2, Containment Inspection Program. See the response to Item 76 for additional discussion on this seal. For additional discussion, see Item #243 response.

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Item Request Response 81 8.1.27.2-W-07 LRA Amendment VYNPS lists the following structure issues under operating experience for this AMP.

Documentation of the operating experience with structural repairs was provided to

" Concrete pad above JD diesel generator day tank sinking and cracking the Inspection Team in the following format:

Degradation of Cooling Tower structural column Concrete pad above the JD diesel generator day tank Provide the documentation for these issues showing when, where and how they were WO 99-1090-000 discovered. Also, provide the documentation on how these issues were evaluated and WO 99-9746-001 resolved with a discussion on the need for any follow-up inspections.

Degradation of cooling tower structural columns Provide the most recent inspection results for the reactor building overhead crane WO 05-5158-000 rails/girders, reactor building (a few examples of areas where aging has been WO 97-5357-004 discovered), cooling towers, and intake structure (a few examples of areas where aging WO 97-5327-00 has been discovered). Provide the last three inspection reports for the drywell floor liner WO 03-1243-009 seal.

Intake structure floor concrete repair WO 04-1745-000 The concrete pad above the JD diesel generator day tank is in a high traffic area.

Degradation was identified by personnel transiting the area. The cracked concrete slab was replaced. This was essentially a design issue, in that the original pad was not designed to bear the weight of the fuel oil delivery truck. The reference WO replaced the pad and added bollard columns to prevent vehicles from driving over the pad. No further follow-up inspections are required.

Degradation of cooling tower structural columns was discovered during routine fall and spring structural inspection PMs. These columns were replaced in kind. Follow-up inspections are performed during the routine fall and spring structural inspection PMs.

The most recent inspection and repair results for the Turbine Building overhead crane were provided to the Inspection Team. Included were reports of two different inspections, repair information and monitoring plans. Both the Reactor and Turbine Building overhead cranes are in scope of the Maintenance Rule and are subject to the same inspection and corrective action programs. Recent Reactor Building overhead crane inspections have identified only mechanical and electrical deficiencies (i.e. trolley motors, brakes, etc.). The results for the Turbine Building overhead crane were provided in lieu of the Reactor Building overhead crane because the recent inspection results involve structural elements and show the effectiveness of the Maintenance Rule crane inspection program. The Structures Monitoring Program will be enhanced (Project document revision) to describe how the program takes credit for the structural inspection program being performed through the Maintenance Rule crane inspection program.

Examples of inspections for cooling tower aging are included in the referenced WOs above.

As stated in other responses, LRDP-02 will be revised to indicate that the drywell floor liner seal will be covered under the containment inspection program, not the structures monitoring program. The seal was replaced two refueling outages ago, and the seal inspection report for last outage has already been provided to the inspection team.

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Item Request Response Degradation of intake structure floor concrete was discovered during routine diver PM inspections performed every refueling outage. The small washed out area was repaired with an underwater concrete repair product. Follow-up routine diver PM inspections will be performed every refueling outage.

82 B.1.27.3-W-01 RAI 3.6.2.2.N-08 Explain which VYNPS individual is responsible for the coordination of Vernon Dam FERC inspections. Explain the process of VYNPS interfacing with FERC with respect There has not been any need for site to coordinate or interface with Vernon Dam's to Vernon Dam and if there are any plant procedures for the interface. If there are plant Federal Energy Regulatory Commission (FERC) inspection. VYNPS does not have procedures for dealing with FERC, provide a current copy. Explain if VYNPS has any an individual responsible for coordinating, interfacing, collecting and reviewing FERC influence on what and when repairs are made on Vernon Dam from a management or inspection report. There is no site procedure for dealing with FERC and obtaining a economic standpoint. Provide the most recent Vernon Dam assessment performed by current copy. Reports are normally received on site after each inspection. VYNPS FERC. Explain how VYNPS receives the report and if the report is independently does not have any influence on what and when repairs should be made from reviewed by any VYNPS personnel such as in systems or design engineering. management or economics standpoint.

CLOSED TO RAI 3.6.2.2.N-08 83 B.1.27.3-W-02 RAI 3.6.2.2.N-08 The operating experience for this AMP states that daily inspections are made of Vernon Dam and periodic underwater inspections are made on the Dam. Explain what As stated in LRA section 2.4.5, Vernon Dam is not part of the site structures owned organization makes the daily inspections and the underwater inspections. Explain how by VYNPS. Dam inspections are regulated by the Federal Energy Regulatory often the underwater inspections are performed and what determines the frequency. Commission (FERC), which licenses the dam and associated power block. Daily Explain if VYNPS has ever independently inspected Vernon Dam. Explain if any inspections are performed by the dam owner's (e.g. Trans Canada, maintenance flooding has occurred which required additional FERC inspections beyond the normal 5 personnel. And, underwater inspections are performed by divers once every 5 years year. The operating experience states that areas of degradation were found on Vernon as required by FERC. No evidence of flooding to require additional FERC Dam during the 2002 FERC inspection and will continue to be monitored. Explain if the inspections beyond the normal 5 year. As stated in the inspection reports, maximum continued monitoring is by FERC on a five year cycle or by VYNPS personnel on a rise in stage cause by a breach will not exceed 1.7 feet under either 50 or 100 year more frequent basis. Explain the type and number of staff that work at Vernon Dam on flood condition. The areas of degradation, found on Vernon Dam during the 2002 a daily basis to maintain it. Explain if and how any personnel at Vernon Dam have the FERC inspection, are monitored by FERC on a five year cycle. However, daily ability to communicate immediately with responsible individuals at VYNPS should a inspection by the dam owner also supplements these inspections. Number and type problem develop at the Dam which could affect the availability of plant cooling water. of staff at Vernon Dam on daily basis is not known. Although not proceduralized, any significant problem with dam is expected to be communicated to the site.

In accordance with NEI 95-10, Rev. 6, Appendix C, Reference 4 (pages C-20 through C-25), "License Renewal Issue No. 98-0100, Crediting FERC-Required Inspection and Maintenance Programs for Dam Aging Management," FERC inspections may be credited for aging management activities. The Vernon Dam is under FERC jurisdiction and that its inspection and maintenance program is in conformance with FERC requirements. The NRC guidance in the referenced section of NEI 95-10 states "It is the staff's opinion that dam inspection and maintenance programs under the jurisdiction of FERC or the Army Corps of Engineers, continued through the period of the license renewal, will be adequate for the purpose of aging management (page C-25)."

During the period of the onsite inspection Vermont Yankee Staff provided a copy of the most recent FERC inspection for the Vernon dam to the NRC Staff.

CLOSED TO RAI 3.6.2.2.N-08 Page 30 at 150 11114120071-37:59 PM 1 1/1 4/2007 1 :3 7:59 PM Page30 of 150

Item Reauest Resoonse ItmRaus esos 84 B.1.30.1-M-01 LR Commitment 26 Since the applicant is currently and periodically sampling and analyzing the cooling water of the other systems "controlled" by VYNPS's existing program-the stator No, as stated in LRA Section B.1.30.1, rather than sampling, procedures will be cooling water and plant heating boiler systems-is it also the intent of the applicant to enhanced (License Renewal Commitment 26) to flush the John Deere diesel cooling periodically sample and analyze the John Deere Dieset cooling water system? water system and replace the coolant and coolant conditioner every three years.

85 B.1 *30.2-M-01 LRA Amendment Section XI.M2 of the GALL notes that a "water chemistry only" program may not be fully effective for verification of corrosion or SCC in slow flow or stagnant flow areas. The Yes, the one-time inspection program described in LRA Section B.1.21 includes GALL further suggests that for some of these "susceptible locations" a one-time inspections to verify the effectiveness of the water chemistry control aging inspection verification program may be appropriate. Do you intend to implement a "one- management programs by confirming that unacceptable cracking, loss of material, time inspection (or some other program) to verify existence of corrosion or SCC in and fouling is not occurring.

these "susceptible locations"?

To provide further clarification, the effectiveness of the Water Chemistry Control -

Auxiliary Systems, BWR, and Closed Cooling Water programs is confirmed by the One-Time Inspection program. This requires an amendment to the license renewal application to change the Appendix A, SAR supplement descriptions for the Water Chemistry Control -Auxiliary Systems, BWR and Closed Cooling Water programs to explicitly state One-Time Inspection Program activities will confirm the effectiveness of these programs.

86 B.1.30.2-M-02 LRA Amendment Section XI.M2 - Element Number four (4) - of the GALL notes that the staff considers a BWR water chemistry program as a "...mitigation program and (that it) does not provide Yes, the one-time inspection program described in LRA Section B.1.21 includes detection of any aging effects..,". The GALL further states that "...inspection of select inspections to verify the effectiveness of the water chemistry control aging components (should) be undertaken to verify the effectiveness of the program..." The management programs by confirming that unacceptable cracking, loss of material, applicant's AMP does not present any other program - other than the indirect results of and fouling is not occurring.

their existing water chemistry program - to verify effectiveness of the chemistry control program. Do you intend to perform "other" inspections, as suggested by the GALL, To provide further clarification, the effectiveness of the Water Chemistry Control -

"...to ensure that significant degradation is not occurring and that intended functions of Auxiliary Systems, BWR, and Closed Cooling Water programs is confirmed by the system components will be maintained during the extended period of operation..."? One-Time Inspection program. This requires an amendment to the license renewal application to change the Appendix A, SAR supplement descriptions for the Water Chemistry Control -Auxiliary Systems, BWR and Closed Cooling Water programs to explicitly state One-Time Inspection Program activities will confirm the effectiveness of these programs.

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Item Request Response 87 B.1.30.3-M-01 LRA Amendment The applicant's exception for this AMP states that "...monitoring pump performance parameters is of little value in managing effects of aging on long-lived, passive CCW This AMP does not ensure that a stagnant flow condition or crevice will not be system components..". The associated GALL for this AMP (XI.M21; Element 4) states periodically present in system piping during the period of extended operation.

that "...control of water chemistry does not preclude corrosion or SCC at locations of Preventing stagnant flow conditions is not a recommended preventive action in stagnant flow conditions or crevices...". How does this AMP ensure that a stagnant flow NUREG-1801,Section XI.M21. As stated in LRA Section B.1.20.3, passive condition or crevice will not be periodically present in system piping during the period of intended functions of pumps, heat exchangers and other components will be extended operation? adequately managed by the Water Chemistry Control - Closed Cooling Water Program through monitoring and control of water chemistry parameters. Also the one-time inspection program described in LRA Section B.1.21 includes inspections to verify the effectiveness of the water chemistry control aging management programs by confirming that unacceptable cracking, loss of material, and fouling is not occurring.

To provide further clarification, the effectiveness of the Water Chemistry Control -

Auxiliary Systems, BWR, and Closed Cooling Water programs is confirmed by the One-Time Inspection program. This requires an amendment to the license renewal application to change the Appendix A, SAR supplement descriptions for the Water Chemistry Control -Auxiliary Systems, BWR and Closed Cooling Water programs to explicitly state One-Time Inspection Program activities will confirm the effectiveness of these programs.

88 B.1.30.3-M-02 [Original Response]

No, functional and performance testing are not aging management actions. They

[Original Question] are maintenance rule activities and not part of the Water Chemistry Control - Closed The applicant's exception for this AMP also states that "....in most cases, functional Cooling Water Program. As stated in LRA Section B.1.30.3, the Water Chemistry and performance testing verifies that the component active functions can be Control - Closed Cooling Water Program takes exception to this recommendation of accomplished and as such would be included as part of the maintenance rule.... Does NUREG 1801,Section XI.M21.

this AMP reference or refer to "maintenance rule activities" as part of planned aging [Follow-up Response]

management actions; i.e., actions which address GALL XI.M21 "parameters As stated in Section 4.20 of LRPD-02, the Service Water Integrity Program, in monitored/inspected"? accordance with NRC GL 89-13, includes condition and performance monitoring

[Follow-up Question] Clarify commitment to performance monitoring/testing of HX activities. As these activities are already part of the existing program, a separate (fouling) and pumps (LoM) managed using OCCW (SWI) and CCCW (WCC-Aux & commitment is not necessary.

WCC-CCW) AMPs.

As stated in the LRA and prior RAI responses, the Water Chemistry Control -

Auxiliary Systems and Water Chemistry Control - Closed Cooling Water programs do not include performance or functional testing of heat exchangers or pumps. The programs are preventive programs which maintain the water chemistry within specified limits to minimize loss of material, cracking and fouling. Also, as described in LRA Section B.1.21, the One-Time Inspection program will verify the effectiveness of the water chemistry control aging management programs by confirming that unacceptable cracking, loss of material, and fouling is not occurring.

Therefore, the passive intended functions of pumps, heat exchangers, and other components will be adequately managed without condition or performance monitoring. [Condition and performance testing of heat exchangers and pumps is performed under the Maintenance Rule 10CFR50.65, but is not considered part of these aging management programs.]

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Item Request Response 89 A-P-01 Section 13 includes all the systems that have intended functions that meet 10 CFR Please clarify the rationale for the unusual numbering system used for auxiliary systems 54.4(a)(2) for physical interaction. The aging management review of these systems after the first 12. (Note: This question is arbitrarily linked to the first item of Table 3.3.1- that have functions that met 10 CFR 54.4(a)(2) for physical interaction was done 13-1) separately from the review of systems with intended functions that met 10 CFR 54.4 (a)(1) or (a)(3). The results of this review therefore needed to be presented separately so that they could be distinguished from the 10 CFR 54(a)(1) and (a)(3) review. Table 3.3.1-13 would be the next sequential table number after the remainder of the auxiliary system tables. To indicate individual systems included in the aging management review for (a)(2), Table 3.3.1-13 is subdivided by system.

For example, Table 3.3.1-13-1 is for the augmented off gas system, a system which only has components included for (a)(2). For the core spray system, Table 3.3.1 6 shows the components included for (a)(2) but since the system is also in scope for other reasons, Table 3.2.2-2 shows the components included for 54.4(a)(1) and (a)(3). This numbering system was chosen so that these systems and the components that had intended functions unique for 54.4(a)(2) could be uniquely identified and reviewed separately. This allows a reviewer to clearly distinguish which component types in a system were included for 10 CFR 54.4(a)(2) for physical interaction. Since most of these systems are auxiliary systems they were added as part of the auxiliary systems section.

90 3.1.1-14-P-01 This response assumes that the question is referring to the tables in Section 3.3.2-

"Support" is not listed as an intended function Please clarify which IF (SNS, SRE, 13 for components included for 10 CFR 54.4(a)(2). This function is described in and/or SSR) is intended. Section 2.3.3.13 under "System Description (pg. 2.3-65) and in the definition in Table 2.0-1 for "Pressure boundary." As shown in the component type tables in Section 2.3.3-13, a footnote states "For component types included under 10 CFR54.4(a)(2), the intended function of pressure boundary includes providing structural/seismic support for components that are included for non-safety-related SSCs directly connected to safety-related SSCs" when this function is appropriate.

Pressure boundary was only used because there is no difference in the aging management review regardless of whether the component intended function is pressure boundary or structural support, and if the pressure boundary intended function of the component is maintained the structural support function will be maintained. This definition of providing structural/seismic support would be equivalent to the intended function of SSR as defined in Table 2.0-1.

Page 33 of 150 1:3 7:59 PM 11/14/2007 1:37:59 1111412007 PM Page 33 of 150

Item Request Response 91 3.6.2.2-N-01 RAI 3.6.2.2.N-01 In LRA, Table 3.6.2-1, under Cable connections (metallic parts), you have stated that no aging effects requiring management and no AMP is required. Further, in LRA, Table VYNPS electrical AMR AMRE-01 in section 4.1.4.4 states for cable connections 3.6.1 under discussion of cable connection metallic parts, you have stated that cable (metallic parts) connections outside of active devices are taped or sleeved for protection and operating "An evaluation of thermal cycling, ohmic heating, electrical transients, vibration, experience with metallic parts of electrical cable connections at VYNPS indicated no chemical contamination, corrosion, and oxidation stressors for the metallic parts of aging effects requiring management. Electrical cable connections (metallic parts) are electrical cable connections identified no aging effects requiring management:

subject to the following aging stressors: thermal cycling, ohmic heating, electrical -Metallic parts of electrical cable connections potentially exposed to thermal cycling transients, vibration, chemical contamination, corrosion, and oxidation. NUREG-1801, and ohmic heating are those carrying significant current in power supply circuits.

Revision 1, AMP XI.E6, "Electrical Cable Connection not Subject to 10 CFR 50.49 Typically, power cables are in a continuous run from the supply to the load.

Environmental Qualification Requirements," specifies that connections associated with Therefore, the connections are part of an active component that is controlled by cables within the scope of license renewal are part of this program, regardless of their Maintenance Rule and is not subject to aging management review.

association with active or passive components. Also, refer to pages 107, 256, and 257 -The fast action of circuit protective devices at high currents mitigates stresses of NUREG-1 833, "Technical Bases for Revision to the License Renewal Guidance associated with electrical faults and transients. In addition, mechanical stress Documents," for additional information regarding AMP XI.E6. Provide a basis associated with electrical faults is not a credible aging mechanism because of the document including an AMP with the ten elements for cable connections or provide a low frequency of occurrence for such faults. Therefore, electrical transients are not justification for why an AMP is not necessary. applicable stressors.

-Metallic parts of electrical cable connections exposed to vibration are those associated with active components that cause vibration. Since active components are controlled by Maintenance Rule, they are not subject to aging management review.

-Corrosive chemicals are not stored in most areas of the plant. Routine releases of corrosive chemicals to areas inside plant buildings do not occur during plant operation. Such a release, and its effects, would be an event, not an effect of aging. The location of electrical connections inside active components protects the metallic parts from contamination. Therefore, this stressor is not applicable.

-Oxidation and corrosion usually occur in the presence of moisture or contamination such as industrial pollutants and salt deposits. Enclosures or splice materials protect metal connections from moisture or contamination. Therefore, oxidation and corrosion are not applicable stressors.

Based on the evaluations of the stressors above, there are no aging effects requiring management for metallic components of connections and no AMP is required CLOSED TO RAI 3.6.2.2.N-01 1 1/14/2007 1*: 7:5 PM . *~~f* *. ......... ,* *m * ** * * *t** ..

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Item Request Response 92 3.6.2.2-N-02 VYNPS electrical AMR Section 4.3.4 of AMRE-01.

In LRA, Table 3.6.2-1, under switchyard bus (switchyard bus for SBO) and connections Connection surface oxidation for aluminum switchyard bus is not applicable since all you have stated no aging effects requiring management and no AMP is required. switchyard bus connections requiring AMR are welded connections. No aging NUREG 1800, Rev. 1, Standard Review Plan for Review of License Renewal effects have been identified for welded connections on switchyard bus for SBO.

Application for Nuclear Power Plants, Section 3.6.2.2.3 identifies loss of preload is an aging effect for switchyard bus connections. Torque relaxation for bolted connection is a concern for switchyard bus connections. An electrical connection must be designed to remain tight and maintain good conductivity through a large temperature range.

Meeting this design requirement is difficult ifthe material specified for the bolt and the conductor are different and have different rates of thermal expansion. For example, copper or aluminum bus/conductor materials expand faster than most bolting materials. If thermal stress is added to stresses inherent at assembly, the joint members or fasteners can yield. If plastic deformation occurs during thermal loading (i.e., heat-up) when the connection cools, the joint will be loose. EPRI document TR-104213, "Bolted Joint Maintenance & Application Guide," recommends inspection of bolted joints for evidence of overheating, signs of burning or discoloration, and indication of loose bolds. Provide a discussion why torque relaxation for bolted connections of switchyard bus is not a concern for VYNPS.

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Item Request ResDonse 93 3.6.2.2-N-03 LRA Amendment Provide AMR line item for transmission conductor connections in Table 3.6.2-1.

Address any aging effects requiring management. LRA Table 3.6.1 and section 3.6.2.2.3 will be revised as shown below:

Table 3.6.1 item # 12 -Transmission conductors and connections.

Aging Effects - Section 3.6.2.2.3 Transmission conductors are un-insulated, stranded electrical cables used outside buildings in high voltage applications. The transmission conductor commodity group includes the associated fastening hardware, but excludes the high-voltage insulators. Major active equipment assemblies include their associated transmission conductor terminations.

Transmission conductors are subject to aging management review if they are necessary for recovery of offsite power following an SBO. At VYNPS, transmission conductors located between switchyard breakers K-1 /K-1 86 and startup transformers T-3-1A/T-3-1B support recovery from an SBO event. Other transmission conductors are not subject to aging management review since they do not perform a license renewal intended function.

AMRE-01 The aging effect for transmission conductors found in industry reviews are loss of conductor strength and loss of material (wear).

The prevalent mechanism contributing to loss of conductor strength of an ACSR transmission conductor is corrosion, which includes corrosion of the steel core and aluminum strand pitting. Corrosion in ACSR conductors is a very slow acting mechanism, and the corrosion rates depend on air quality, which includes suspended particles chemistry, S02 concentration in air, precipitation, fog chemistry and meteorological conditions. Air quality in rural areas generally contains low concentrations of suspended particles and S02, which keeps the corrosion rate to a minimum. Tests performed by Ontario Hydroelectric showed a 30% loss of composite conductor strength of an 80 year old ACSR conductor due to corrosion.

ACAR conductors are more resistant to loss of conductor strength since the core of the conductor is an alloy of steel and corrosion resistant metals. AMR conclusions regarding ACSR conductors conservatively bound ACAR conductors.

The National Electrical Safety Code (NESC) requires that tension on installed conductors be a maximum of 60% of the ultimate conductor strength. The NESC also sets the maximum tension a conductor must be designed to withstand under heavy load requirements, which includes consideration of ice, wind and temperature. These requirements are reviewed concerning the specific conductors included in scope at VYNPS.

The 4/0 ACSR conductors have the lowest initial design margin of any transmission conductors included in the AMR. The Ontario Hydro test and the NESC requirements illustrate with reasonable assurance that transmission conductors will have ample strength through the period of extended operation.

Therefore, loss of conductor strength due to corrosion of the transmission conductors in not an aging effect requiring management for the period of extended operation.

Loss of material due to mechanical wear can be an aging effect for strain and suspension insulators that are subject to movement caused by transmission Page 36 of 150 11/14/20071:37:59 1111412007 PM 1:37:59 PAW Page 36 of 150

Item Request Response conductor vibration or sway from wind loading. Design and installation standards for transmission conductors consider sway caused by wind loading. Experience has shown that transmission conductors do not normally swing and that when they do swing because of substantial wind, they do not continue to swing for very long once the wind has subsided. Wear has not been identified during routine inspection; therefore, loss of material due to wear in not an aging effect requiring management.

This report documents a review of industry OE and NRC generic communications related to the aging of transmission conductors in order to ensure that no additional aging effects exist beyond those previously identified. This report also documents a review of plant-specific OE, which did not identify any unique aging effects for transmission conductors.

94 3.6.2.2-N-04 VYNPS electrical AMR Section 4.2 in AMRE-01.

In LRA, Table 3.6.2-1, under Transmission conductors, you have stated that no aging The prevalent mechanism contributing to loss of conductor strength of an ACSR effects requiring management and no AMP is required. NUREG 1800, Rev. 1, transmission conductor is corrosion, which includes corrosion of the steel core and Standard Review Plan for Review of License Renewal Application for Nuclear Power aluminum strand pitting. Corrosion in ACSR conductors is a very slow acting Plants, Section 3.6.2.2.3 identifies loss of conductor strength due to corrosion is the mechanism, and the corrosion rates depend on air quality, which includes aging effect of high voltage transmission conductor. The most prevalent mechanism suspended particles chemistry, S02 concentration in air, precipitation, fog chemistry contributing to loss of conductor strength of aluminum core steel reinforce (ACSR) and meteorological conditions. Air quality in rural areas generally contains low transmission conductor is corrosion which includes corrosion of steel core and concentrations of suspended particles and S02, which keeps the corrosion rate to a aluminum strand pitting. Degradation begins as a loss of zinc from the galvanized steel minimum.

core wires. Corrosion rate depend largely on air quality, which includes suspended Tests performed by Ontario Hydro showed a 30% loss of composite conductor particles chemistry, sulfur dioxide concentration in air, precipitation, fog chemistry and strength of an 80-year old ACSR conductor due to corrosion.

meteorological conditions. Explain why loss of conductor strength due to corrosion is The National Electric Safety Code (NESC) requires that tension on installed not an aging effect requirement management for transmission conductors at VYNPS. conductors be a maximum of 60% of the ultimate conductor strength. The acceptance criteria for VYNPS is less than 40% loss of composite conductor strength per NESC.

Aluminum conductor alloy reinforced (ACAR) conductors are used at VYNPS as well as ACSR conductors.

ACAR conductors are more resistant to loss of conductor strength since the core of the conductor is an alloy of steel and corrosion resistant metals.

Conclusions for ACSR conductors conservatively bound ACAR conductors. The National Electric Safety Code (NESC) requires that tension on installed conductors be a maximum of 60% of the ultimate conductor strength. The acceptance criteria for VYNPS is less than 40% loss of composite conductor strength per NESC.

Aluminum conductor alloy reinforced (ACAR) conductors are used at VYNPS as well as ACSR conductors.

ACAR conductors are more resistant to loss of conductor strength since the core of the conductor is an alloy of steel and corrosion resistant metals.

Conclusions for ACSR conductors conservatively bound ACAR conductors.

Therefore, corrosion of transmission conductors is not aging effect requiring management and an AMP is not required.

1:37:59 PM I 1/14/2007 1:37.59 PM Page 37 of 150 1111412007 Page 37 of 150

Item Request Response 95 3.6.2.2-N-05 Per VYNPS electrical AMR Section 4.4 in AMRE-01:

In LRA, Table 3.6.2-1, under high voltage insulators, you have indicated that no aging effects requiring management and no AMP is required. In LRA, Section 3.6.2.2.2, you Various airborne materials such as dust, salt and industrial effluents can have also stated that at VYNPS surface contamination build-up on insulator is not a contaminate insulator surfaces. The buildup of surface contamination is gradual concern. NUREG 1800, Rev. 1, Standard Review Plan for Review of License Renewal and in most areas. Such contamination is washed away by rain; the glazed insulator Application for Nuclear Power Plants, Section 3.6.2.2.3 identifies surface surface aids this contamination removal.

contamination is the aging effect of high voltage insulators. Various airborne materials VYNPS is not located near the seacoast where salt spray is prevalent, or near such as dust and industrial effluent can contaminate insulator surfaces. The buildup of facilities that discharge soot.

surface contamination is gradual and in most areas such contamination is washed away At VYNPS, as in most areas of the New England transmission system, by rain; the glazed insulator surface aids this contamination removal. However, a large contamination build up on insulators is not a problem. Therefore, surface buildup of contamination enables the conductor voltage to track along the surface more contamination is not an applicable aging mechanism for the insulators at VYNPS.

easily and can lead to insulator flashover., Surface contamination can be a problem in areas where there are greater concentration of airborne particles such a near facilities that discharge soot. Explain why surface contamination is not a concem at VYNPS.

96 3.6.2.2-N-06 Section 3.4.2 in AMRE-01 and FSAR Section 5.2.3.4.3 Are all electrical and I&C containment penetrations EQ? If not, provide AMRs and AMPs for non-EQ electrical and I&C containment penetrations. The AMRs should At VYNPS, electrical penetration assemblies are included in the EQ program and include both organic ( XLPE, XLPO, and SR internal conductor/pigtail insulation, etc.,) are not subject to aging management review.

as well as inorganic material (such as cable fillers, epoxies, potting compounds, connector pins, plugs, and facial grommets).

1:3 7:59 PMPM Page 38 of 150 7 1/1 4/2007 1:37.59 1111412007 Page 38 of 150

Item Request ResDonse 97 3.6.2.2-N-07 LR Commitment 32 In LRA, Table 3.6.1 under metal enclosed bus, you have stated that an evaluation of LRA Amendment metal enclosed bus for VYNPS determined that VYNPS does not have any phase bus that support a license renewal function. 10 CFR 54.4 (a)(3) requires, in part, that all Resolution - The VY UFSAR Section 8.3.3 describes three offsite power sources.

systems, structures, and components relied on in safety analyses or plant evaluation to The immediate access circuit from the 345kV yard through the 345/115kV perform a function that demonstrates compliance with the commission's regulations for autotransformer to the startup transformers, the alternate immediate access circuit station black out (10 CFR 50.63) are within the scope of license renewal. VYNPS from the 115kV yard (Keene Line) through the startup transformers. The delayed FSAR Section 8.3.3 states that electric power supplied from the transmission network access circuit is available by opening the generator no-load disconnect switch and to the on-site electric distribution system by two independent circuits, one immediate establishing a feed from the 345kV switchyard through the main and aux access and one delayed access. The immediate access circuit is supplied from the transformers.

345 kV transmission system through 345 kV/1 15 kV auto-transformer. It feeds the on-site electric distribution system through the two 115 kV to 4160 V start up transformers 3.6.2.2-N-07(a) and is available immediately following a loss of generating capability. The delay access No, there are no non-segregated phase buses in the path from the startup circuit is available by opening the generator no-load disconnect switch and establish a transformers to the 4.16 safety buses.

feed from the 345 kV switchyard through the main generator step-up transformer and unit auxiliary transformer to the 4160 V safety buses. Answer the following questions 3.6.2.2-N-07(b) and support them with a main one line diagram: The delayed access circuit from the 345KV switchyard through the main generator step-up transformer and unit aux transformer uses the iso-phase bus for connection 3.6.2.2-7(a). In regard to the above, are non-segregated phase buses used to connect and is in scope for license renewal. The VYNPS Metal-Enclosed Bus program will the start up transformers (T-3A and T-3B) (lower sides) to 4.16 kV safety buses? be consistent with GALL XI.E4. The VYNPS Metal-Enclosed Bus program will perform visual inspection of the internal portions of the bus for cracks, corrosion, 3.6.2.2-7(b). In regard to the above, are iso phase buses used to connect the delay foreign debris, excessive dust buildup, and evidence of water intrusion. Internal bus access circuit from the 345 kV switchyard through the main generator step-up supports will be inspected for structural integrity and signs of cracks. Enclosure transformer and unit auxiliary transformer? assemblies will be inspected for evidence of loss of material and elastomers will be inspected to manage cracking and change in material properties.

3.6.2.2-7(c). In regard to the above, are non-segregated phase buses used to connect The first inspection will be completed before the period of extended operation and the unit auxiliary transformer (lower sides) to 4.16 kV safety buses? every five years thereafter.

If the answer to a, b, or c is yes, explain why metal enclosed buses (iso phase and/or The Metal-Encased Bus Program will be added to the following LRA sections:

non-segregated phase buses) are not in scope of license renewal and not require an Section 2.5 - Electrical and I&C Systems AMP. Section 3.6 - Electrical and Instrumentation and Controls Table 3.6.1 Table 3.6.2-1 Appendix A Appendix B This requires an amendment to the LRA The Metal-Enclosed Bus Program will be added to the following AMR and AMPER.

LRPD Aging Management Program Evaluation Results AMRE Electrical Screening and AMR This is LR commitment #32.

3.6.2.2-N-07(c)

No, there are no non-segregated phase buses in the path from the Unit Aux Transformer to the 4.16 safety buses.

Summary The in-scope components required for recovery from a SBO do not include any non-segregated phase bus that requires aging management review.

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Item Reauest Response ResDonse 98 3.6.2.2-N-08 LR Commitment 43 10 CFR 54.4 (a)(3) requires, in part, that all systems, structures, and components RAI 3.6.2.2.N-08 (SSCs) relied on in safety analyses or plant evaluation to perform a function that demonstrates compliance with the commission's regulations for station black out (10 The long-lived, passive components from the Vernon dam switchyard to the plant CFR 50.63) are within the scope of license renewal. Vernon Hydroelectric Station has are in scope and subject to AMR. The underground cables and connections are been designated as the Station Blackout (SBO) alternate ac (AAC) source and is used included in E2. The Vernon Dam is regulated by FERC and inspected per FERC to meet SBO requirements 10 CFR 50.63. Are all SSCs (including electrical regulations.

components) associated with Vernon Hydroelectric Station included in the scope of licensee renewal? If they are not, explain why not. If they are, provide an AMR for long- LR Commitment 43 provides a rquirement for testing of the two 13.8 kV cables from lived, passive SSCs associated with the hydro station. the two VHS 13.8 kV switchgear buses to the 13.8 kV/69 kV step up transformers before the period of extended operation and at least once every 10 years after the initial test.

99 B.1.27.3-W-03 Vernon Dam is used for hydro-electric generation and is the alternate AC source of Are there any other license renewal intended functions other than SBO, associated with power for VYNPS. The deep basin beneath the west cooling tower is a safety-the Vernon Dam? related, reinforced concrete structure constructed on bedrock. The basin acts as a reservoir to replace the evaporative and other losses occurring during alternate cooling system (ACS) operation, providing a one-week supply of makeup for the alternate cooling cell in the event of a loss of Vernon Dam. The Vernon Dam has no other intended functions for (10CFR54.4(a)(1) or (a)(2). The Vernon Dam is credited for station blackout (10CFR50.63), intended function 10CFR54.4(a)(3).

100 The NRC requested additional information on licensing renewal, specifically on how The NRC requested additional information on underground cables, buried piping and aging management applied to passive components in the Vernon Hydroelectric Station. support systems. The requested information was provided to the NRC during the onsite review. In addition a FERC inspection report was provided for the dam and NPCC Document A-3, Emergency Operational Criteria.

101 B.1.30.3.M.04 LRA Section B.1.30.3 includes an exception to the performance and functional GALL Xl .M21 discusses pump and heat exchanger testing in the parameters monitored testing discussed in the detection of aging effects attribute. This exception and its

/ inspected attribute. Is this testing part of the Water Chemistry Control - Closed justification are equally applicable to the parameters monitored / trended attribute.

Cooling Water Program?

102 B.1.9-K-11 Provided QA Surveillance 99-010, QA Audit Report QA-2-2005-VY-1 and CR-VTY-Please provide a copy of QA Surveillance 99-010 and more recent QA surveillance of 2005-00196.

Diesel Fuel Monitoring Program.

103 B.1.9-K-12 Provided Section 5 of OP2106 Rev. 18, App. D JD Diesel day tank sample location Please identify sample point locations on John Deere diesel and diesel fire pump oil is at the bottom of this tank. Fire pump diesel fuel supply & sample point are 2 storage tanks. (Diesel Fuel Monitoring Program) inches from the bottom of the diesel fire pump fuel tank.

104 B.1.9-K-13 This information has been provided via spreadsheet of monthly analysis data for the Please provide 2000 and 2003 sample results spreadsheet. Also sample lab results for Main Fuel Oil Storage Tank for 2000 and 2003. Also, provided example analysis main storage tank and EDG day tanks are desired. (Diesel Fuel Monitoring Program) results for samples from the Walpole NH supplier tank, the John Deere diesel storage tank, the diesel fire pump storage tank, and the EDG day tanks.

105 B.1.30.3-M-05 Third party assessment of "Chemistry" on May 6, 2003 provided for review.

Please provide a copy of recent third party assessment of the water chemistry control - Summary states that closed cooling water systems are monitored and treated to closed cooling water program. provide a chemical environment that minimizes corrosion rates.

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Item Request ResDonse 106 B.1.2.3-M-04 The existing examinations for the reactor vessel closure studs (Category B-G-2) are The Reactor Vessel Stud Program takes exception to GALL based on relief request IS[- based on ASME Code Case N-652. Code Case N-652 has been endorsed by the

03. The NRC does not believe this should be an exception. NRC per Table 1 of Regulatory Guide 1.147, Revision 14.

Review the relief request and ASME code. If this is not an exception, revise the program document.

107 The commitment to manage locations CUF>1.0 should be on a numbered commitment LR Commitment 27 list.

License renewal commitment #27 has been prepared, to address the above items.

The commitment to analyze the limiting location for environmentally assisted fatigue should be on a numbered commitment list.

NOTE: The commitment is in section 4 (4.3.3.?) not in App. B 108 Identify the site specific calculations for core plate hold down bolt preload. No site specific calculation was found in the VYNPS current licensing basis for the number / preload of the core plate hold-down bolts required to prevent lateral motion of the core plate.

109 Accurately state / describe the information / documentation requested. Be as specific This information was provided during the onsite review.

as possible. The NRC requested a copy of the Vernon hydro-drawing.

Not an NRC question. Close item.

110 The NRC inspector had a one-line diagram and asked if bus duct was used for the Immediate Access: The cables are used from the startup transformers to the 4 KV immediate access source or the delayed access source. The inspector was interested if buses and overhead 115 KV bare cable is used to supply the transformers with bus an AMR applied to either source for segregated or non-segregated bus, if used. above the transformers.

Not an NRC question. Close item.

Delayed Access: There is isophase bus duct used on the back-feed for the 22 KV system and it connects to the auxiliary transformer.

111 Please provide results of the last inspection of the welds between the rerouted CRD Provided results of 1985 inspection retum line and the RWCU system. (BWR CRD Return Line Nozzle Program) 112 Please provide documentation related to resolution of vessel clad cracking. Provided documentation as requested during NRC interview.

113 The BWR penetrations program second exception allows a smaller inspection than the The inspection of the vessel penetrations tol/2' versus 1/2T was approved via Relief code Request ISI-09. This relief request is in turn based on ASME Code Case N-613-1.

(1/2' vs. 1/2" vessel wall thickness). What is the basis for this? Code case N-613-1 has been endorsed by the NRC per Table 1 of Regulatory Guide 1.147, Revision 14, August 2005.

This is conservatively identified in the BWR Penetrations Program description as an exception to GALL because it required relief to the existing code requirements.

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Item Request Response 114 Do the VY penetration nozzles have a bored (cold worked) safe end extension? This question was erroneously applied to the vessel instrumentation nozzles.

BWRVIP-49-A requires no additional inspection requirements for cold worked safe If yes, they require additional inspection. ends for the instrumentation nozzles.

The question should have been directed at the SLC/DP nozzle, for which the discussion of cold worked safe ends is found in the BWRVIP-27-A inspection guideline 3.4.1. Per drawing 5920-52666 RO implementing the inspection guidelines of BWRVIP-27-A as applicable to VY, but that does not include the entire safe end extension examination required of those plants with cold worked safe ends.

115 Accurately state / describe the information / documentation requested. Be as specific Yes, this is a typographical error and it should have said that the Buried Piping as possible. Inspection Program provides reasonable assurance that the effects of aging will be LRPD-05 section 4.4.1 second paragraph states that the BWR CRD Return Line Nozzle managed such that the current licensing basis for the period of extended operation.

program provides reasonable assurance. Should this have been the Buried Piping This item has been addressed through revision of LRPD-05.

Inspection Program?

116 B.1.17-N-04 The intent of the VY AMP B.1.17 is to inspect for water in manholes and to test the GALL X1 .E3 under program description states, in part, that periodic actions such as in-scope medium-Voltage cables.

inspecting for water collection in cable manholes, and draining water, as needed to prevent cables from being exposed to significant moisture. The above actions are not sufficient to assure water is not trapped elsewhere in the raceways. In addition to the above periodic actions, in scope, medium voltage cables are tested to provide an indication of the condition of the conductor insulation. VYNPS AMP B.1.17 under same element states that periodic actions will be taken to prevent cables from being exposed to significant moisture, such as inspecting for water collection in cable manholes and draining water, as needed. In-scope medium-voltage exposed to significant moisture and voltage will be tested to provide an indication of the condition of the conductor insulation. It is not clear to the NRC if you intend to use these periodic actions to preclude cable testing. If this is the case, provide a technical justification of why removing water in the cable manholes will provide assurance that water is not present elsewhere in the conduits or duct banks. If this is not the case, revise your AMP as appropriate to requires both testing and inspecting water accumulation in the manholes.

117 B.1.17-N-05 Yes, all of the in-scope medium-voltage cables will be subject to testing per the GALL Xl .E3 recommends testing all in-scope inaccessible medium-voltage cables. Are program requirements.

all inaccessible medium-voltage cables within the scope of license renewal tested?

118 B.1.17-N-06 LRA Amendment GALL Xl.E3 under parameters monitored/inspected states that the specific type of test performed will be determined prior to the initial test and is to be a proven test for LRA Appendix B.1.17 will be revised to state that the specific type of test to be detecting deterioration of the insulation system due to wetting such as power factor, performed will be determined prior to the initial test and is to be a proven test for partial discharge test, or polarization index, as described in EPRI TR-103834-P1-2, or detecting deterioration of the insulation system due to wetting as described in EPRI other testing that is state-of-the-art at the time the test is performed. VYNPS B.1.17 TR-103834-P1 -2, or other testing that is state-of-the-art at the time the test is under the same attribute only states that the specific type of test performed will be performed.

determined prior to initial test. Revise your AMP to be consistent with GALL or explain how do you ensure that the test to be performed will be in accordance with industrial guideline or that is the state-of-the-art at the time the test is performed.

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Item Reauest ResDonse 119 B.1.17-N-07 Yes, the manholes are inspected on an annual basis. An example was provided Do you currently inspect water in the man holes. Are there any existing procedures for during the onsite inspection inspecting man holes. Provide a copy of these procedures.

120 B.1.17-N-08 LRA Amendment GALL Xl .E3 defines medium-voltage cable is the voltage level from 2kV to 35kV VYNPS AMP B.1.17 defines medium-voltage cable is the voltage level from 2kV to VY does not have any medium-voltage cable in-scope that is greater than 15KV.

15kV. Revise the scope of the inaccessible medium - voltage level to be consistent with LRA Appendix B.1.17 will define medium-voltage cable as voltage level from 2kV to GALL or provide a technical justification that why the water tree phenomenon is not 35kV.

applicable to voltage level greater than 15kV. Are there any inaccessible medium -

voltage cables within the scope of licensee that are greater than 15kV.?

121 B.1.18-N-03 VYNPS B.1.18 AMP under corrective actions states that "an engineering evaluation GALL Xl.E2 under corrective actions states that such an evaluation is to consider the will be performed when the test acceptance criteria are not met in order to ensure significance of the test results, the operability of the component, the reportability of the that the intended functions of the electrical cables can be maintained consistent with event, the extend of the concern, the potential root causes for not meeting the test the current licensing basis. This evaluation is performed in accordance with the acceptance criteria, the corrective actions required, and likelihood of recurrence in Entergy corrective action process per procedure EN-LI-1 02. This procedure addition to 10 CFR Part 50, Appendix B. VYNPSB.1.18 under the same element only provides the stated elements to consider including the extent of the concern, the refers to 10 CFR Part 50 Appendix B to address corrective actions. Revise your AMP potential root causes for not meeting the test acceptance criteria, the corrective corrective actions to be consistent with GALL or provide a justification of why such actions required, and likelihood of recurrence. See procedure details below:

specific corrective actions are not necessary.

Adverse Condition - An event, defect, characteristic, state or activity that prohibits or detracts from safe, efficient nuclear plant operation or a condition that could credibly impact nuclear safety, personnel safety, plant reliability or non-conformance with federal, state, or local regulations. Adverse conditions include non-conformances, conditions adverse to quality and plant reliability concerns Operability Evaluation - A written evaluation of a Condition Report, to determine impact of the identified condition on the operability of structures, systems or components. The operability evaluation includes a determination for reportability.

Extent of Condition - An evaluation to identify the total population of items that have or may have the same problem as identified in the original CR problem statement.

The intent of the Extent of Condition review focuses on a determination of any potential impact to the operability/functionality of similar components, equipment, systems, human performance traps/issues, or organizational processes/programs.

Root Cause - The most basic cause(s) for a failure or a condition that, if corrected or eliminated, will preclude repetition of the event or condition.

Corrective Action - Corrective actions include actions intended to preclude repetition of significant conditions and those intended to correct adverse conditions.

Corrective Actions to Preclude Repetition - A type of corrective action intended to correct the root cause of a condition and thereby preclude repetition.

A copy of EN-LI-1 02 had been provided to the onsite review team.

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Item Request Response Item Request Resoonse 122 B.1.18-N-04 VYNPS electrical AMR, AMRE-01, states that "Cables and connections in the high-Why is the high range radiation monitor cable is not considered in scope of XI.E2. range reactor building area monitoring system, support a license renewal intended function. However, the entire length of these cables are EQ and do not require aging management since they are subject to replacement based on a qualified life.

123 B.1.19-N-03 Commitments numbers are being supplied in a table for all commitments.

For all new AMP provide a commitment number and the implementation period for this new program.

124 B.1.19-N-04 LRA Amendment GALL Xl .El under scope of program states that this inspection program applies to accessible electrical cables and connections within the scope of license renewal that "in a structure" means inside the plant not outside. The VYNPS B.1.19 will be are installed in adverse localized environments caused by heat or radiation in the revised to state that the program applies to accessible electrical cables and presence of oxygen. VYNPS AMP B.1.19 under the same element you have stated connections within the scope of license renewal that are installed in adverse that this program will include accessible insulated cables and connections installed in localized environments caused by heat or radiation in the presence of oxygen.

structures within the scope of license renewal and prone to adverse localized environments. Clarify if the scope of this program include only insulated cables and connections installed in structures which (structures) are in scope of license renewal and prone to adverse localized environments or insulated cables and connections within the scope of license renewal that are installed in adverse localized environments..

Why are structures included in the scope of the AMP. Modify the scope of the program as appropriate to remove the confusion.

125 B.1.19-N-05 A revised copy of GALL for XI.E1 was provided.

Explain why the GALL X.E1, EQ, is included in the basic document for non-EQ insulated cables and connections program.

126 3.6.2.2-N-09 No, the two types of fuse holders are all located in active devices.

GALL XI.E5 states that the fuse holder (not part of a larger assembly) metallic portions are subject to fatigue due ohmic heating, thermal cycling, electrical transients, frequent manipulation, vibration, chemical contamination, corrosion, and oxidation. In the LRA Table 3.6.1 item 3.6.1-6, you have stated that NUREG-1801 aging effect is not applicable to VYPNS. In AMRE-01 Revision 0 Page 14 of 108, you have stated that VYNPS employs two general types of fuse holders. The first type is the bolt-mount fuse holder that uses either a lug or cap-screw to secure the fuse between the clamps. The second type of fuse holder is the metallic clamp fuse holder, which uses the spring tension. Installation data for cables and connections indicated that the only fuse holders installed at VYNPS that utilize metallic clamps to secure the fuse are either part of active assembly or are located in circuits that perform no license renewal indented functions. Are there any bolt-mount fuse holders in scope of licensee renewal that are not part an active assembly. If there are, explain why aging effects as identified in the GALL are not applicable.

127 B.1.1 -L-06 The maintenance inspections being credited are inspections that are being Program Description item. The LRA says "Buried components are inspected when performed on an as needed basis since there are no routine scheduled maintenance excavated during maintenance". Is maintenance performed on an as needed basis or is inspections of buried piping.

it on a scheduled frequency?

1. 77 1......

1/ 4/2....

11/1

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Item Reauest Resnonse ResDonse 128 B.1.1-L-07 The focused inspection will be performed within the first 10 years of the period of Program Description item. The LRA says "A focused inspection will be performed within extended operation, unless an opportunistic inspection occurs within this ten-year the first 10 years of the period of extended operation...." The LRA seems to address period as stated in LRPD-02 section 4.1.B.4.b of the Buried Piping Inspection inspections that occur both before and during the period of extended operation; the Program and in Appendix B.1.1 of the LRA. The first sentence in the third Appendix A reference does not clarify this confusion. When does VY plan to perform paragraph of the program description in the LRA describes a review of operating these focused inspections? experience (if available) for examinations of buried piping for relevant information and is not a required inspection.

Inspections of buried carbon steel piping were performed in 2003 which is within the 10 years prior to the period of extended operation. These inspections revealed no coating or piping degradation.

129 B.1.1-L-07 Appendix A is correct as written. The focused inspection is specified for the ten Program Description item. Depending on the response to the above question, please years immediately after entering the period of extended operation. This is clarify the Appendix A reference, as needed. consistent with the SER for Brunswick dated March 2006.

130 B.1.1-L-08 LR Commitment 1 Acceptance Criteria item. The GALL Report says "Any coating and wrapping degradations are reported and evaluated according to site corrective actions It was the intent of the enhancement specified in B.1.1 to revise appropriate procedures." The LRA says "Coating and wrapping degradation, or loss of material due sections of procedure PP 7030 to include attributes of coating damage and evidence to corrosion, is evaluated in accordance with the site corrective action program." PP of corrosion. This would include updating sections 4.3 & 4.8.

7030, Section 4.8, is very general, e.g., "signs of degradation," "areas of degradation."

Does VY intend to enhance this guidance, as well as that addressed in question B.1.1-L-04?

131 B.1.1-L-09 Yes, this is a typographical error and it should have said that the Buried Piping Operating Experience item. . Why does LRDP-05, Section 4.4.1 reference the BWR Inspection Program provides reasonable assurance that the effects of aging will be CRD Return Line Nozzle Program? managed such that the current licensing basis for the period of extended operation.

This item was addressed in revision to LRPD-05.

132 B.1.30.2-M-03 Provided Revision 1 of Technical Justification for Continued Operation of Entergy An exception to BWRVIP - 130 criteria for feedwater copper was noted. Please provide Northeast Vermont Yankee (ENVY) with Feedwater Copper > 0.2 ppb.

related information. (Water Chemistry Control - BWR Program) 133 B.1.30.2-M-04 Third party assessment of BWR Water Chemistry control from March 2001, May Please provide a copy of recent third party assessments of the Water Chemical 2003 and April 2005 were provided for review.

Control - BWR Program.

134 B.1.8-L-02 Type A testing) and due to the expectations of VY on maintaining operating Detection of Aging Effects item. PP 7006, Section 4.4.4, refers to a Type A Test, which procedures current, OP 4029 (test procedure) was retired. By retiring the procedure will be developed. Please explain. that is conducted once every 10 to 15 years, forces the test engineer to develop a Type A Test lAW Tech Specs 6.7.C & PP 7006, Section 4.4.4 that adopts the latest test equipment, processes, software programs, and testing philosophies into the infrequently conducted evolution (SOER 91-01), thereby ensuring that the complex Type A testing process is thoroughly understood by the test engineer. With the inception of 10CFR50 Option B, containment integrity is adequately monitored between Type A tests.

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Item Request ResDonse 135 B.1.8-L-03 Under current regulations and NEI guidance, the one time change does not affect Monitoring and Trending item. The GALL Report says 'The frequency of these tests the Type A test interval or number of tests to be conducted during the, period of depends on which option (A or B) is selected. With Option A, testing is performed on a extended operation.

regular fixed time interval as defined in 10 CFR Part 50, Appendix J." The LRA says "The first Type A test after the April 1995 Type A test shall be performed no later than April 2010. This is a one-time extension of the NEI 94-01, 10 year Type A test interval to 15 years. NRC approved Amendment 227 to Facility Operating License DPR-28 for VYNPS to extend the primary containment integrated leak rate testing interval from 10 years to no longer than 15 years on a one-time basis." Amendment 227 refers to its being a one-time extension, so it would not appear to extend into the period of extended operation. Please clarify.

136 B.1.8-L-04 At present, VY does not take direct exception to any provision in RG 1.163. VY Monitoring and Trending item. Does VY take any exception to the testing guidance of does take exception to NEI 94-01. Specifically, with the adoption of License RG 1.163 or NEI 94-01? Amendment 223 of the Alternative Source Term (AST), the Main Steam Line Pathways were determined to be separate radiological (consequences) release paths exclusive of the Primary-Secondary Containment System radiological (consequences) release path. This pathway is subject to the 10CFR50 Appendix J Type C testing methodologies but the calculation methods, leakage-rate summations, and acceptance criteria were determined to be independent of the Primary Containment allowable leakage rate (La). NEI 94-01 does not address the effects AST adoption on a primary containment leakage rate testing program; therefore, an exception to License Amendment 223 for the VY current license and through the possible license extension period is required.

137 B.1.8-L-05 See B.1.8-L-04 exception basis for response.

Acceptance Criteria item. LRPD-02 identifies the following as an exception that the LRA did not. The GALL Report says "Acceptance criteria for leakage rates are defined in plant Technical Specifications. These acceptance criteria meet the requirements in 10 CFR Part 50, Appendix J, and are part of each plant's current licensing basis. The current licensing basis carries forward to the period of extended operation." The LRA says "VYNPS acceptance criteria are defined in plant technical specifications." Please expand on why the acceptance criteria are not consistent with the GALL Report.

138 B.1.8-L-06 VYNPS incorporates, as necessary, lessons learned into the Containment Leak Operating Experience item. Does VYNPS monitor industry issues/events and assess Rate Program from operating experiences identified at VYNPS and industry these for applicability to its own program? operating experiences. The incorporation of the lessons learned follows a process of an understanding of the operating experience, an assessment of the current program to determine applicability, and the document development to affect the change.

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Item Request ResDonse 139 B.1.14-K-01 Operating History search was performed on the following components:

Requested operating experience information on a sample of the heat exchangers included in the Heat Exchanger Monitoring Program if any is available. HPCI gland Seal condenser (E-18-1A)

HPCI Lube oil coolers (E-1 9-1 A)

RCIC lube oil coolers (E-21-1A)

CST aluminum steam reheat coil (E-HB-1)

Drywell atmospheric cooling units (RRU 1, 2, 3, 4)

Drywell equipment drain cooler (E-ESC-1A)

Reactor Recirculation pump seal water coolers (P-18-1 A/B Hx-3)

Reactor Recirculation pump motor upper & lower bearings oil coolers (P-18-1A/B Hx-2)

Reactor Recirculation pump motor air coolers (P-18-1A/B Hx-1)

Keywords used in PCRS:

Fouling Eddy Current Tube replacement Tube plugging Plugging Tube blockage No information was found on the heat exchanger or coolers for any of the above components in PCRS.

EMPAC search on components:

WO 2001-5153 performed 10/04/2002- E-18-lA HPCI Gland Seal condenser Cleaning and inspection WO 1997-8128 performed 04/02/1998- E-19-1A Inspect lube oil side of HPCI lube oil cooler RRU-1 through 4 are inspected and lubricated during refueling outages-External inspections only Attachments provided to the NRC during the onsite review:

WO 2001-5153 WO 1997-8128 NRC has these attachments.

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Item Request Response 140 B.1.14-K-02 The development of the non Service Water (SW) cooled heat exchanger inspection What is the proposed frequency of inspection and basis of the frequency selected for and monitoring plan would be similar to the process which was used for the SW heat the heat exchangers included in the Heat Exchanger Monitoring Program. exchangers.

The scope of this plan would include, but not be limited to, the following heat exchangers and coolers:

Drywell Coolers, RRU-1 through 4 HPCI Gland Seal Condenser, E-18-1A HPCI Lube Oil Cooler, E-1 9-1A RCIC Lube Oil Cooler, E-21-1A CST Reheat Coil, E-HB-1 Drywell Equipment Drain Cooler, E-ESC-1A Reactor Recirculation Pump Seal Water Coolers, P-18-1A HX-3 & P-18-1B HX-3 Recirculation Pump Motor Upper & Lower Bearing Oil Coolers, P-18-1A HX-2 & P-18-1B HX-2 Recirculation Pump Motor Air Coolers, P-18-1A HX-1 & P-18-1B HX-1 The following is an example of the steps which would be used to develop the plan:

1. An initial visual inspection would be performed of the in scope heat exchangers.

This inspection would document the "as-found" conditions. Additional examination methods may be used if "as-found" conditions warrant, (i.e. ultrasonic thickness measurements or radiography). The results of these inspections would be used to establish the frequency of future inspections.

2. Where physically accessible, baseline eddy current data would be obtained. The number of tubes sampled would be determined based on industry best practices and EPRI recommendations. The results of these tests would be used to determine the frequency of future inspections and the number of tubes to be sampled.

3. Future inspections and eddy current examinations would be scheduled via the Preventive Maintenance process.

4. Performance monitoring and trending would be performed in accordance with established fleet procedures.

Once developed the plan would be administered by the onsite engineering organization.

LRCommitment 30 141 B.1.12.1-L-07 Scope of Program item. The GALL Report has requirements in numerous program LRA Amendment elements that are on a six-month frequency. The LRA states that these are on a refueling (twenty-month) frequency. Please discuss and justify the inspection frequency System walkdown every 6 months, starting prior to period of extended operations.

differential for the C02 system.

The VY AMP B.1.1 7 will state that the specific type of test to be performed will be determined prior to the initial test and is to be a proven test for detecting deterioration of the insulation system due to wetting as described in EPRI TR-103834-PI -2, or other testing that is state-of-the-art at the time the test is performed.

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Item Request Response 142 B.1.18-N-04 VYNPS Electrical AMR, AMRE-01 states that "Cables and connections in the high-Why is high range radiation monitor cable not considered in scope of XI.E2? range reactor building area monitoring system, support a license renewal intended function. However, the entire length of these cables are EQ and do not require aging management since they are subject to replacement based on a qualified life.

143 B.1.18-N-05 a) LRPD-02 will be revised under parameter monitored/inspected to state that the GALL XI.E2 under parameter monitored/inspected states that the parameter monitored parameters monitored are determined from the specific calibration, surveillances or are determined from the specific calibration, surveillance or testing performed and are testing performed and are based on the specific instrumentation circuit under based on the specific instrumentation under surveillance or being calibrated, as surveillance or being calibrated, as documented in plant procedures.

documented in plant procedures. VY AMP B.1.18 under same attribute states that LRPD-02, Rev 2 incorporated this change.

results from the calibrations or surveillance of components within the scope of license renewal will be reviewed. The parameters reviewed will be based on the specific (b) LRPD-02 under parameter monitored/inspected will state that the parameters instrumentation circuit under surveillance or being calibrated, as document in the plant monitored are determined from the specific calibration, surveillances or testing calibration or surveillance procedures. performed. The parameter for cable testing is determined from the plant procedures. Cable testing is performed by plant procedures on cables in-scope of a Why does the review of calibration results belong to parameter monitored/inspected XI.E2 that are disconnected during instrument calibration.

attribute?

b. The parameter monitored/inspected for cable testing was not mentioned. What is the parameter for cable testing. Confirm that cable testing will be perform on cables in-scope of XI.E2 that are disconnected during instrumentation calibration.

144 B.1.18-N-06 LRPD-02 will be revised under acceptance criteria to state that calibration results or VY B.1.18 under acceptance criteria address the acceptance criteria for calibration. findings of surveillance-and cable system testing results are to be within the However, it silences on the acceptance criteria for cable testing. What is the acceptance criteria.

acceptance criteria for cable testing? LRPD-02, Rev 2 incorporated this change.

145 B.1.20-K-03 QA Surveillance SRVY 2002-025 and 2003 self-assessment provided during the Please provide QA Surveillance and self-assessment referenced in operating onsite audit.

experience for Oil Analysis Program.

146 B.1.12.1-L-07 LR Commitment 30 Scope of program item. The GALL Report has requirements in numerous program LRA Amendment elements that are on a six-month frequency. The LRA states that these are on a refueling (twenty-month) frequency. Please discuss and justify the inspection frequency The TRM frequencies are based on those that were previously in the Technical differential for the C02 system. Specifications. Entergy VY will re-examine the ability to performing these surveillances at a 6 month or higher frequency, provided that they can be safely performed online. This effort will be started 6 months prior to the period of extended operation and is tracked as License Renewal Commitment #30.

147 B.1.12.1-L-08 The VY Fire Hazards Analysis was provided during the onsite inspection.

Preventive Actions item. The GALL Report says "For operating plants, the fire hazard analysis assesses the fire potential and fire hazard in allplant areas.... The LRA says "The NUREG-1801 Preventive Actions do not specify any measures for preventing aging effects of fire protection structures, systems or components." Has VY performed a fire hazard analysis?

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Ite m Request Response 148 B.1.12.1-L-09 These dampers are in ventilation ducts; therefore, the conditions would be similar to Parameters Monitored/Inspected item. The GALL Report says "Visual inspection of the other ambient conditions in the plant. The duct material is carbon steel. The fire barrier walls, ceilings, and floors examines any sign of degradation such as environment is indoor air.

cracking, spalling, and loss of material caused by freeze-thaw, chemical attack, and reaction with aggregates." The LRA says "Procedures will be enhanced to specify that fire damper frames in fire barriers shall be inspected for corrosion." What is the material (

and environment of the damper frames?

149 B.1.12.1-L-10 Visual exam, consistent with ANSI 45.2.6 Parameters Monitored/Inspected item. What examination technique will be used?

150 B.1.12.1-L-11 LR Commitment 9 Parameters Monitored/Inspected item. The GALL Report says "The diesel-driven fire pump is under observation during performance tests such as flow and discharge tests, Yes. This item is being tracked by License Renewal Commitment #9.

sequential starting capability tests, and controller function tests for detection of any degradation of the fuel supply line." The LRA says "Procedures will be enhanced to state that the diesel engine sub-systems (including the fuel supply line) shall be observed while the pump is running." Is there a VYNPS commitment associated with this enhancement?

151 B.1.12.1-L-12 LR Commitment 8 Acceptance Criteria item. The GALL Report says "Inspection results are acceptable if there are no visual indications (outside those allowed by approved penetration seal This item is being addressed by License Renewal Commitment #8.

configurations) of cracking, separation of seals from walls and components, separation of layers of material, or ruptures or punctures of seals; no visual indications of concrete cracking, spalling and loss of material of fire barrier walls, ceilings, and floors; no visual indications of missing parts, holes, and wear and no deficiencies in the functional tests of fire doors." The LRA says "Acceptance criteria will be enhanced to verify no significant corrosion." How much is "significant?"

152 B.1.12.1-L-13 LR Commitment 8 Acceptance Criteria item. What actions are taken, either with or without significant corrosion? This item is being addressed by License Renewal Commitment #8 153 B.1.12.1-L-14 LR Commitment 8 Acceptance Criteria item. Is there a VYNPS commitment associated with this enhancement? This item is being addressed by License Renewal Commitment #8 154 B.1.12.1-L-15 LR Commitment 9 Acceptance Criteria item. The GALL Report says "No corrosion is acceptable in the fuel supply line for the diesel-driven fire pump." The LRA says "Acceptance criteria will be Evidence of corrosion inside the fuel line would appear as corrosion products in the enhanced to verify that the diesel engine did not exhibit signs of degradation while it fuel filter. Evidence of corrosion in the fuel filter would result in a Condition Report was running; such as fuel oil, lube oil, coolant, or exhaust gas leakage." Does the and an evaluation. Evidence of corrosion would be an inspection criterion for fuel enhancement include corrosion in the fuel supply line of the diesel-driven fire pump? filters removed from service. In addition, the internals of the fuel line are managed by the diesel fuel oil monitoring program.

155 B.1.12.1-L-16 LR Commitment 9 Acceptance Criteria item. Is there a VYNPS commitment associated with this enhancement? Yes. This item is being tracked by License Renewal Commitment # 9 Page SOot 150 11/14120071:37:59 1412007 1.37:59 PM PM Page 50 of 150

Item Reauest ResDonse 156 B.1.12.1-L-17 During the onsite inspection, the OE Coordinator provided the requested information.

Operating Experience item. Has VY experienced any fire-protection-related operating experience? Please describe.

157 B.1.12.1-L-18 VY routinely reviews Industry OE in accordance with fleet procedure, EN-OE-1 00.

Operating Experience item. Has VY reviewed and applied the industry operating The VY OE coordinator routes OE to affected line organization groups, and enters experience that relates to fire protection? action items into the corrective action process to ensure that timely review is completed and documented.

158 B.1.12.1-L-19 No Operating Experience item. Is any VY plant-specific operating experience not bounded by industry operating experience?

159 B.1.12.1-L-20 LR Commitment 8 Program Description item. Does VY inspect the fire dampers? LRA Amendment Yes. Surveillance Test #7134 is the Operating Cycle Test of Fire Barrier Dampers, using procedure OP 4019. VY will add Fire Dampers to the program description.

LR Commitment 8 is provided to enhance inspection procedures to specify that fire protection dampers will be inspected for corrosion, with acceptance criteria provided.

160 B.1.12.1-L-21 Yes. The pump end is identical to the diesel fire pump. It is located in the Intake Program Description item. Does VY have an electric fire pump? Structure. Component ID is P-40-1 B. It is Managed by Fire Water Program via Test Procedure # OP 4105.

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Item Request Response 161 B.1.12.1-L-22 Test Procedures for inspecting and testing Appendix R required equipment are:

Program Description item. How does VY inspect/test Appendix R-required equipment? PROC. # TITLE AP 0042 Plant Fire Prevention and Fire Protection OP 0046 Installation and Repair of Fire Barriers, Penetration Seals, Fire Breaks and Flood Seals.

OP 2186 Fire Suppression Systems OP 3020 Fire Emergency Response Procedure AP 3700 Fire Training OP 4001 Plant Fire Extinguisher Service and Issue OP 4002 Integrity Surveillance of Fire Detectors and Fire Suppression Systems OP 4019 Surveillance of Plant Fire Barriers and Fire Rated Assemblies OP 4103 Fire Protection Equipment Surveillance OP 4104 Fire Hose Hydro Test Surveillance OP 4105 Fire Protection Systems Surveillance OP 4221 Surveillance of Gas Fire Extinguishing Systems OP 4339 Surveillance of Fire Protection Detectors/Instruments OP 4392 Trip Test of Fire System Water Flow Alarms OP 4393 Test of the Cable Vault, Switchgear Room, and Intake Structure C02 Systems OP 4395 Check of Computer/Heating Ventilation Air Conditioning (HVAC)

Shutdown Circuits / Computer Room Halon Act. System OP 4602 Sampling of Fire Fighting Foam for Annual Analysis OP 4800 General Safety Surveillance OP 5327 Calibration of Plant Fire Protection System Instruments AP 6024 Plant Housekeeping and Foreign Material Exclusion/Cleanliness Control PP 7011 Vermont Yankee Fire Protection and Appendix R Program 162 B.1.12.1-L-23 At VY, the program is being developed and will include training, acceptance criteria, Detection of Aging Effects item. The GALL Report says "Visual inspection by fire and qualification as a flire protection qualified individual" ANSI 45.2.6 The inspection protection qualified inspectors...." Of what does this consist, at VY? program, EN-MA-102, will be used.

163 B.1.12.1-L-24 OP 4019 acceptance criteria will be revised to require that any recordable "outside Acceptance Criteria item. The GALL Report says "Inspection results are acceptable if those allowed by approved penetration seal configurations" visual indication be there are no visual indications (outside those allowed by'approved penetration seal identified and entered into the corrective action process for evaluation.

configurations) of cracking,..." OP 4019, Appendix B, allows cracksin poured concrete barriers, fire barriers, concrete block walls, drywall, plaster, silicone foam, pyrocrete, The CA number to complete this action by 12/31/06 is CR-VTY-2006-112. CA-02; and smoke/gas seals. CA-03.

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Item Reauest Response Item Request ResDonse 164 B.1.30.1-M-02 LR Commitment 26 Is the identified enhancement to AMP B.1.30, Water Chemistry Control - Auxiliary Systems, necessary and appropriate for this program? The identified enhancement to AMP B.1.30, Water Chemistry Control - Auxiliary Systems is to enhance procedures to flush the John Deere diesel cooling water system and replace the coolant and coolant conditioner every three years.

A program is necessary to manage loss of material and fouling of carbon steel and copper alloy components in the John Deere diesel cooling water system for the period of extended operation. Due to the size and configuration of the system, periodic sampling of the coolant was deemed unrealistic and the decision was made to flush the cooling water and replace the coolant and coolant conditioner every three years. While this task could have been included in the Periodic Surveillance and Preventive Maintenance program, it was included in the Water Chemistry Control - Auxiliary Systems program to be consistent with other components exposed to treated water, which are managed by water chemistry control programs.

As stated in LRA Section B.1.30.1, rather than sampling, procedures will be enhanced to flush the John Deere diesel cooling water system and replace the coolant and coolant conditioner every three years, (License Renewal Commitment 26) 165 B.1.30.1-M-03 LRA Amendment Confirm that there are no other in-scope systems that rely on this AMP for managing the effects of aging. The following LRA tables credit the Water Chemistry Control - Auxiliary Systems Program for managing the effects of aging.

3.2.2-5, Reactor Core Isolation Cooling (RCIC) System - Summary of Aging Management Evaluation 3.3.2-10, Heating, Ventilation and Air Conditioning (HVAC) Systems - Summary of Aging Management Evaluation 3.3.2-12, John Deere Diesel (JDD) - Summary of Aging Management Evaluation 3.3.2-13-18, House Heating Boiler (HB) System, Non Safety-Related Components Affecting Safety-Related Systems - Summary of Aging Management Evaluation 3.3.2-13-39, Stator Cooling (SC) System, Non Safety-Related Components Affecting Safety-Related Systems - Summary of Aging Management Evaluation The component in the RCIC system that credits this program is a steam heater which is supplied by the house heating boiler system. Similarly, the components in the HVAC systems that credit this program are supplied by the house heating boiler system. Thus, there are no in-scope systems (other than the house heating boiler, stator cooling, and John Deere diesel systems) that rely on this AMP for managing the effects of aging. All other in-scope treated water systems rely on either the Water Chemistry Control - BWR program or the Water Chemistry Control - Closed Cooling Water program for managing the effects of aging.

Items 3.3.1-50 and 3.3.1-51 in LRA Table 3.3.1 will be updated to reflect that the de-mineralized water system is managed by the Water Chemistry Control - BWR Program, as indicated in LRA Table 3.3.2-13-12, aging of components.

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Item Request Response 166 B.1.21-K-04 LRA Amendment LRA Section 3 Table 2's do not list the One-Time Inspection Program with the water chemistry control programs for components for which GALL recommends One-Time LRA Section 3 Table l's discussions provide the link between the One-Time Inspection to verify effectiveness of the Water Chemistry Control Program. Inspection and Water Chemistry Control Program for these components.

To provide further clarification, the effectiveness of the Water Chemistry Control -

Auxiliary Systems, BWR, and Closed Cooling Water programs is confirmed by the One-Time Inspection program. This requires an amendment to the license renewal application to change the Appendix A, SAR supplement descriptions for the Water Chemistry Control -Auxiliary Systems, BWR and Closed Cooling Water programs to explicitly state One-Time Inspection Program activities will confirm the effectiveness of these programs.

167 B.1.21.-K-05 Inspection locations will be based on physical accessibility exposure levels, NDE Please provide sample selection criteria for the small - bore piping one-time inspection techniques, and locations identified in NRC Information Notice 97-46, Un-isolable program. Crack in High-Pressure Injection Piping. The initial population will include all Class 1 small - bore piping.

168 B1.15.2-P-01 Entergy chose to describe the Inservice Inspection and Containment Inservice Please explain why the AMP for ISI (IWB, IWC, & IWD) is not consistent with the GALL Inspection Programs as plant-specific programs rather than comparing to the AMP XI.M1 corresponding NUREG-1801 programs because the NUREG-1801 programs contain many ASME Section Xl table and section numbers which change with different'-

versions of the code. Because of this, comparison with the NUREG-1 801 programs generates many exceptions and explanations which detract from the objective of the comparison. What is really needed is that VYNPS follow the version of ASME Section Xl that is approved for use at VYNPS and accepted by law in -

10CFR5O.55(a). As this is the case, the Inservice Inspection and Containment Inservice Inspection Programs are presented as plant-specific programs so they can be judged on their own merit without the distraction of numerous explanations of code revision.

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Item Request ResDonse 169 B.1.15.2-P-02 Risk-informed ISI is being implemented during the Fourth Ten-Year Interval The AMP for ISI (IWB, IWC, & IWD) makes no mention of any risk-informed program. (9/1/2003 - 8/31/2013). Surface examination of ASME Section XI, Class I, Please confirm whether or not there are current or future plans for the implementation Examination Categories B-F, C-F-i, and C-F-2 (4" NPS and larger) are conducted in of risk-informed SI. accordance with Code Case N-663. All areas of the subject welds identified as susceptible to outside surface attack shall be surface examined during the Fourth Ten-Year Interval in accordance with Code Case N-663. Code Case N-663 incorporates lessons learned for risk-informed initiatives and industry examination experience by requiring that an evaluation be conducted to identify locations, if any, where a surface examination would be of benefit from a generic piping degradation perspective. The results of the evaluation identify where O.D. degradation is most likely to occur by reviewing plant-specific programs and practices, and operating experience. If the potential for degradation is identified, Code Case N-663 defines examination techniques, volumes, and frequencies. As such, implementing Code Case N-663 identifies appropriate locations for surface examination and eliminates unnecessary examinations.

VYNPS plans to continue surface examination of ASME Section Xl, Class I, Examination Categories B-F, C-F-i, and C-F-2 (4" NPS and larger) in accordance with Code Case N-663 in subsequent inspection intervals. If Code Case N-663 is not incorporated into the ASME Section Xl code edition and addendum approved by the Nuclear Regulatory Commission in 10 CFR 50.55a for the subsequent interval, a relief request will be submitted as was done for the Fourth Inspection Interval.

170 Provide the basis for determining the inspections required for BWRVIP-48. Particularly PP7027, Appendix B states clearly that these brackets are examined as if they are address furnace sensitized, I A W VIP 48-A.

whether VYNPS has any furnace sensitized material or Alloy 182 material that requires EVTI.

171 B.1.27.1-W-04 The following Block Wall Inspection Reports and drawings were provided during the Provide the last two inspection reports for one un-reinforced Masonry Wall without onsite inspection:

bracing, one reinforced Masonry Wall without bracing and one steel braced Masonry Wall. -Masonry Wall Routine Surveillance Walkdown Sheet for Wall G-1 91145-9 dated 10/16/02 (un-reinforced wall)

-Drawing B-191600 Sheet 8 Rev 0 (from walkdown)

-Attachment C VYP-007 R1 Masonry Wall Routine Surveillance Walkdown Sheet for Wall G-191145-9 dated 9/1/93 (un-reinforced wall)

-Drawing B-191600 Sheet 8 Rev 0 (from walkdown)

-Attachment C VYP-007 R1 Masonry Wall Routine Surveillance Walkdown Sheet for Wall G-1 91145-4 dated 9/28/93 (steel braced wall)

-Attachment C VYP-007 RO Masonry Wall Routine Surveillance Walkdown Sheet for Wall G-191145-4 dated 9/10/87 (steel braced wall)

-Drawing B-1 91600 Sheet 7 Rev 1 (from 1993 walkdown)

-Masonry Wall Routine Surveillance Walkdown Sheet for Wall G-191627-4 dated 10/16/02 (reinforced wall)

-Attachment C VYP-007 R1 Masonry Wall Routine Surveillance Walkdown Sheet for Wall G-191627-4 dated 9/1/93 (reinforced masonry wall)

-Drawing B-191600 Sheet 105 Rev 0 (reinforced masonry wall, from walkdown)

-Drawing B-191600 Sheet 105 Rev 1 (reinforced masonry wall) 172 Please provide copies of OP4339 and EN-OE-100, procedures related to the Fire Water OP4339 and EN-OE-1 00 were provided during the onsite inspection.

System Program.

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Item Request ResDonse 173 In Section 2b Preventive actions of LRPD-02 and it is stated that there are no Yes, The Water Chemistry Control - Closed Cooling Water and BWR programs at preventive actions. GALL says that monitoring of water chemistry to control pH and VYNPS control PH and corrosive contaminants and could be effective in controlling concentration of corrosive contaminants and treatment with hydrazine are effective in selective leaching. Therefore any system and components with both the selective reducing selective leaching. Do any of the systems that have selective leaching as an leaching and the water chemistry programs as aging management programs are AMP have a treated water environment that performs any of these treatments to control included measures that could be effective in controlling the aging effect of selective selective leaching? leaching.

174 What is the flaw evaluation calculation for the jet pump diffuser welds? Is this The jet pump diffuser welds calculations are contained in: GE-NE-B1 3-01935, Rev.

calculation considered a TLAA? 2, Jet Pump Assembly Welds Flaw Evaluation Handbook for Vermont Yankee, July 1999.

This is not a TLAA.

175 Will UT of the flawed jet pump diffuser welds continue? These welds are scheduled for UT examination during RFO 26.

Following RFO -26, if there are no changes to the observed indications, the Please identify any change to the exception identified in LRA. inspections will revert to EVT-1 inspections lAW BWRVIP-4.

If yes, please provide the exact wording in LRA supplement.

(Note: EVT-1 does not provide flow propagation verification.)

176 Will VYNPS continue to inspect 10% of CRD guide tubes every 12 years? VYNPS inspects guide tubes lAW BWRVIP-47-A and plans to continue to do so.

Additional question: PP-1027 stated that 2VT-3 inspections were performed. BWRVIP EVT-1 inspections are conducted on CRGT-2 and CRGT-3.

stated that 4 CRD Guide tube weld locations were recommended to be inspected; VT-3 inspections are conducted on CRGT-1 and FS?GT-APRIN-1 2 locations (VT-3) 2 locations (EVT-1)

Please describe the inspection for all 4 locations. Does applicant inspect all 4 welds or only 2 welds?

177 Will VYNPS continue to inspect the top guide at the rate of 10% every 12 years? LR Commitment 2 This question has been addressed in Question # 14. The BWR Vessel Internals Program at VYNPS is consistent with the program described in NUREG-1801,Section XI.M9, BWR Vessel Internals with the exceptions and enhancement noted in LRA Section B.1.7. As stated in NUREG-1801, the extent of the examination and its frequency will be based on a ten percent sample of the total population, which includes all grid beam and beam-to-beam crevice slots.

LR Commitment two provides details for the top guide inspection frequency.

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Item Reauest Response Item Request ResDonse 178 What is the exam history, results, schedule and current status of shroud H8 and H9 In RFO 19 (1996) Vermont Yankee-performed an inspection of welds H8 and H9 welds? which meets the requirements of BWRVIP-38 for a baseline examination. The following describes the rationale for this statement. The baseline strategies for welds H8 and H9 are shown in Figures 3-4 and 3-5 of BWRVIP-38. The load multiplier is determined from Figures 5-1. In Vermont Yankee's case this is a 0.41. The flaw tolerance is determined from figures 5-1 (for H8) and 5-2 (for H9) for plants with support legs. For both welds the flaw tolerance of 100 %. The minimum examination coverage for a flaw tolerance of 100% is 10% for both H8 and H9. The coverage was 25% for weld H8 and 22% for weld H9 during the RFO 19 (1996) examination.

No flaws were found. Therefore an adequate baseline of welds H8 and H9 was performed.

No welds other than H8 and H9 require examination is accordance with BWRVIP-38 for a plant with Vermont Yankee's core shroud support configuration. The NRC requires inspection tooling and methodologies be developed that allow the welds in the lower plenum to be made accessible. This requirement applies to the VYNPS shroud support leg welds. This inspection remains an open item with the NRC per response to BWRVIP-38.

The re-inspection interval is established in BRWVIP-38, Paragraph 3.3.2, that states "if no flaws were found during the previous inspection, re-inspections are performed on ten-year intervals if UT techniques were used..." The RFO 19 (1996) H8 and H9 examination was an ultrasonic test augmented with eddy current and no flaws were found. Therefore the re-inspection interval is ten years if UT techniques are used, and six years if EVT-1 techniques are used (but see below). Accordingly, re-inspection of H8 and H9 were re-inspected in RFO 25(2005), by EVT-1 nine years following the baseline exam.

179 B.1.22-M-03 WANO Assessment Report will be available for on-site review during return audit Please provide a recent third party assessment of the preventive maintenance program. (week of 5/15/06).

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Item Request Response 180 B.1.22.M-04 The Periodic Surveillance and Preventive Maintenance program includes two types Following the proposed enhancement to the Periodic Surveillance and Preventive of tasks, inspections and surveillances.

Maintenance Program, will it be apparent that these tasks contain an aging management element? Inspections include various visual or other non-destructive examinations to manage loss of material, cracking, and fouling of components. Following the proposed enhancements, it will be apparent that these tasks contain an aging management element. To properly inspect for evidence of loss of material, cracking, or fouling, the inspector must be aware that he is looking for these aging effects and as such new guidance to identify these aging effects will be included as required.

Surveillances include the secondary containment capability check, which will confirm the absence of aging effects for reactor building exterior concrete walls during the period of extended operation; leakage testing on the equipment lock doors, which will confirm the absence of aging effects for the rubber door seals during the period of extended operation; and temperature monitoring during operability testing of diesel generators to confirm the absence of fouling of diesel heat exchangers during the period of extended operation. To perform these tests, the performer does not need to be aware that he is confirming the absence of aging effects. If the applicable acceptance criterion is not met, the performer will initiate a condition report. In accordance with the corrective action program, causes for the condition will be evaluated, including those that are due to aging of components.

181 B.1.22-L-01 The Walkdown program is not exclusive of any system material condition. It should Program Description item. The GALL Report says "The External Surfaces Monitoring be noted that the walkdown process may find signs of external piping degradation program is based on system inspections and walkdowns. This program consists of that would be evaluated for potential impact to interior piping surfaces. The periodic visual inspections of steel components such as piping, piping components, walkdown program is not intended to inspect interior piping and component surface ducting, and other components within the scope of license renewal and subject to AMR unless they have been revealed for inspection during maintenance and repairs. As in order to manage aging effects. The program manages aging effects through visual indicated in the tables in Section 3 of the LRA, the System Walkdown program inspection of external surfaces for evidence of material loss. Loss of material due to manages aging for external surfaces of carbon steel, stainless steel, cast iron, low boric acid corrosion is managed by the Boric Acid Corrosion Program." The LRA says alloy steel, aluminum, and copper alloy components. The program also manages "This program entails inspections of external surfaces of components subject to aging loss of material from internal surfaces in situations in which internal and external management review. The program is also credited with managing loss of material from material and environment combinations are the same such that external surface internal surfaces, for situations in which internal and external material and environment condition is representative of internal surface condition.

combinations are the same such that external surface condition is representative of internal surface condition." What materials are within the scope of this AMP?

182 B.1.22-L-02 For current term operation, system walkdowns use "eye contact" examination.

Program Description item. What examination methods are used? System Engineers are not qualified in visual examination methods such as those used to qualify welding. The Entergy walkdown procedure provides a listing and a checklist of examinations to be performed during the walkdown. Plant issues ranging from standard housekeeping to equipment problems are documented and acted upon accordingly through work planning and the condition reporting system.

For the License Renewal term, under the System Walkdown program, visual inspection activities are performed and associated personnel are qualified in accordance with site controlled procedures and processes.

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Item Request Response 183 B. 1.22-L-03 System Walkdowns , both online and during refueling outages,, have found corrosion Operating Experience item.. Has VY experienced any external surfaces-related on piping and component surfaces. For insiance, each relueling, the interior of the operating experience? Please describe. condenser hotwell and waterboxes are inspected. Repairs and or more detailed inspections are implemented as required. In Refueling Outage 24 (November 2005) examination of spring cans supporting service water piping revealed rust and the need for recoating. Corrective actions driven by condition reporting and work order planning has resulted in scheduling repair for the 2006 outage.

184 B.1.22-L-04 Vermont Yankee System Engineers have received training in the EPRI Aging Operating Experience item: Has VY reviewed and applied the industry operating Management Field guide, which in effect is a collection of OE from many nuclear experience that relates to external surfaces? plant systems, both mechanical and electrical, as well as buildings and structures intended to provide specific details of corrosion and degradation throughout the plant. Review of OE is an ongoing activity for Vermont Yankee System Engineers intended to ensure latest issues are known and to continue to develop background related to assigned systems.

185 B.1.22-L-05 Through its condition reporting system, Vermont Yankee will contribute to industry Operating Experience item: Is any VY plant-specific operating experience not bounded OE as its Condition Reporting Committee directs. Aging related issues with by industry operating experience? Vermont Yankee are typical of industry based OE.

186 B.1.22-L-06 Vermont Yankee is a Boiling Water Reactor and therefore does not have a Boric Program Description item. Is boric acid leakage that falls/sprays on VY components Acid Corrosion Prevention program. The Standby Liquid Control system, which managed by the Boric Acid Corrosion Program? contains Sodium Pentaborate, and is maintained in a clean condition. Rare cases of leakage from standby liquid control system valve packing or other system components have occurred, but were promptly corrected prior to impacting the intended function of components subject to aging management review for license renewal. The external surfaces of SLC components and components in the area are managed by the System Walkdown program.

187 B.1.22-L-07 LR Commitment 24 Scope of Program item. Please expand the explanation of the enhancement identified LRA Amendment in LRPD-02, page 218.

The enhancement in LRPD-02, page 218 was identified after the LRA was submitted to NRC foe review. Entergy decided that the System Walkdown program implementing procedure should be enhanced to specify. that systems in scope and subject to aging management review for license renewal in accordance with 10 CFR 50.54 (a)(1) and (a)(3) shall be walked down. Guidance as to what systems are walked-down is currently included in less formal plant guidelines. Also, although the System Walkdown program implementing procedure currently provides guidance to inspect nearby systems that could impact the system being walked down, Entergy decided that this guidance should be clarified. The enhancement in LRPD-02, page 218 is commitment # 24 on the list of commitments for license renewal.

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Item Reauest Response ResDonse 188 B.1.22-L-08 LR Commitment 24 Scope of Program item. Enhancements will need specific commitments.

Vermont Yankee commits to those items related to Aging Management and will update the Entergy walkdown procedure accordingly commensurate with the License Renewal schedule. Training in the EPRI Field Guide is ongoing at this time.

The enhancement in LRPD-02, page 218 is commitment # 24 on the list of commitments for license renewal.

See also related Audit Item #384 189 B.1.22-L-09 These items are documented on a monthly basis, as found during walkdowns, in Parameters Monitored/Inspected item. The LRA does not specify the same examples walkdown reports. Any material condition is assessed at the time discovered and that the GALL Report does, e.g., material wastage, leakage, insulation condition, etc. acted upon according to its conditions. All system conditions, including those found What is the justification for not addressing these parameters? in walkdowns, plant monitoring and daily operations are summarized in Quarterly System Health reports.

190 B.1.22-L-10 LR Commitment 24 Parameters Monitored/Inspected item. Several of these parameters are not addressed in EN-DC-178. Should this procedure be enhanced? Specifically discussed during License Renewal program reviews were insulation and the need to visually examine it for signs of leakage, corrosion beneath and missing insulation. License Renewal Commitment 24 addresses the Walkdown procedure.

191 B.1.22-L-11 Walkdowns may find signs of piping external surface degradation and will assess Detection of Aging Effects item. GALL focuses on the pertinent surfaces. LRPD-02, any potential impact on interior surfaces.

page 215, says that the program will manage the loss of material for internal and external surfaces by visual inspection of external surfaces. How is this accomplished? Consistent with GALL Section XI.M36, External Surfaces Monitoring, the VYNPS System Walkdown program will manage loss of material for internal surfaces exposed to the same environment as the external surfaces. External surface condition on components exposed to the same internal and external environments is indicative of internal surface condition. Components with signs of external surface degradation will be assessed for potential impact on interior surfaces impact.

192 B.1.22-L-12 In addition to the service water piping spring cans noted in Question 183 and a few Operating Experience item: Has VYNPS experienced any external surfaces-related other examples are:

operating experience? Please describe. 1. Cooling Tower wood structural member splitting (normal aging and checking of wood). VY's preventative maintenance program drives inspection and replacement as required.

2. Switchyard tower base age related cracking. Evaluated for structural impact, found satisfactory, future work to coat bases.

193 B.1.22-L-13 Yes, the OE has helped identify specific causes and "best practice" repairs. The Operating Experience item. Has VYNPS reviewed and applied the industry operating EPRI Aging Management Field Guide has been particularly useful.

experience that relates to external surfaces?

194 B.1.22-L-14 Review of Aging Related OE to date has not found such OE.

Operating Experience item. Is any VY plant-specific operating experience not bounded by industry operating experience?

195 B.1.22-L-15 These examples are representative. VYNPS can supply others on specific systems Operating Experience item. Several findings are identified under the OE tab. Are these as requested.

the total findings that were made or are they simply representative?

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Item Request Response 196 Regarding the UT indication at 215 degrees on the RPV cladding adjacent to a dryer VYNPS performed enhanced UT's in accordance with commitment described in support log: Does VYNPS plan to re-inspect this indication by UT? BVY 92-055 and BVY 93-112. These UT's were performed from the RPV OD and determined that the cracks do not penetrate to the RPV base metal. The steam dryer lugs will be re-inspected in accordance with BWRVIP-48 by VT-1.

197 3.1.1 P-01 Cumulative fatigue damage is a generic term. However, only when fatigue damage On page 3.1-55, the component type 'supports stabilizer pads support skirt' is managed accumulates to the point that the component cracks is the function of the using TLAA - metal fatigue. In all cases where the LRA lists "Cracking - fatigue" as the component in jeopardy. VYNPS uses the aging effect of cracking due to fatigue to AERM, change it to "Fatigue damage" (applies to multiple Table 1 items but is asked represent the physical result of cumulative fatigue damage. The meaning of only once). "Cracking - fatigue" is consistent with the intent of "Cumulative Fatigue Damage".

LR Commitment 34 198 3.1.1-02-P-01 On page 3.1-36, the component type 'closure flange studs, nuts, washers and bushings' LRA Amendment and the component type 'other pressure boundary bolting, flange bolts and nuts (N6A, N6B, N7), CRD flange cap-screws and washers' are managed using TLAA - metal Revised Answer to 5/11/2006 email fatigue. Please confirm that aging of these components will be managed using the new "Bolting Integrity" AMP. The Bolting Integrity Program will be implemented prior to the period of extended operation in accordance with commitment number #34.

Email Edit 5/11/2006 - 3.1.1-02-P-01 Generic question 2: When bolting integrity AMP is added, many AMR Table 2 items need to be revised. Will VYNPS provide bolting The identification of TLAA - metal fatigue in the aging management program integrity program to manage bolts? column is provided as a convenient means to indicate that these components are susceptible to cracking due to fatigue which is addressed in Section 4.3.1 of the LRA as a TLAA. It is not implying that TLAA - metal fatigue is an aging management program. An aging management program is one of the three resolutions for the evaluation of a TLAA.

The component type closure flange studs, nuts, washers and bushings are for the reactor head and are managed by the Reactor Head Closure Studs Program described in Section B.1.23 of the LRA which is comparable with the NUREG-1801 XI.M3 program. This approach is consistent with the GALL Bolting Integrity program XI.M1 8 which states that the aging management of reactor head closure studs is addressed by XI.M3, and is not included in this program. A Bolting Integrity Program is in development that will address the aging management of other bolting in the scope of license renewal.

199 3.1.1-02-P-02 Many NUREG-1801, Volume 2 items are very similar in terms of materials, On page 3.1-54, the component type 'internal attachments shroud support ring pad (1) environment, aging effect and aging management program. Where a NUREG-1801 shroud support feet (14) jet pump riser pads (20) core spray brackets (4) guide rod item lists the same component, the choice is straightforward. Where NUREG-1 801 brackets (2) steam dryer brackets (4) dryer hold-down brackets (4) surveillance does not match the specific component, the selection of the item to compare to the specimen holder brackets feedwater sparger brackets (8)' is managed using TLAA - aging management review results is somewhat arbitrary. Item IV.B1-14 would metal fatigue. Please explain why these components are not managed in accordance certainly have been an acceptable choice for the comparison. However, in this with GALL v2 item IV.B1-14. particular case, the components were considered a subset of the reactor vessel (hence the listing within the reactor vessel table) and the comparison was made to the fatigue item within the NUREG-1801 BWR reactor vessel table. The aging management review results in NUREG-1801 are the same for item IV.A1-7 as for IV.B1 -14.

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Item Request Response ResDonse 200 3.1.1-13-P-01 LRA Amendment In many cases, loss of material is managed using Water chemistry control - BWR.

Please confirm that the VYNPS Water Chemistry - BWR AMP is consistent with GALL As stated in LRA Section B.1.30.2, the Water Chemistry Control - BWR Program is XI.M32, "One-Time Inspection," as well as with XI.M2, "Water Chemistry." consistent with the program described in NUREG-1801,Section XI.M2, "Water Chemistry." The One-Time Inspection Program, described in LRA Section B.1.21 Edit from 5/11/2006 email - In many cases (e.g. page 3.1-67 piping& fitting), loss of includes inspections to verify the effectiveness of the water chemistry control aging material is managed using Water chemistry control - BWR alone. Please confirm that management programs (Water Chemistry Control - Auxiliary Systems, Water the VYNPS Water Chemistry - BWR AMP is consistent with GALL XI.M32, "One-Time Chemistry Control - BWR, and Water Chemistry Control - Closed Cooling Water)

Inspection," as well as with XI.M2, "Water Chemistry." by confirming that unacceptable cracking, loss of material, and fouling is not occurring. As stated in LRA Section B.1.21, the One-Time Inspection Program is a new program which will be consistent with the program described in NUREG-1801,Section XI.M32, "One-Time Inspection."

LRA Tables 3.1.1, 3.2.1, 3.3.1, and 3.4.1 indicate that the One-Time Inspection Program is credited along with the water chemistry control programs for line items for which GALL recommends a one-time inspection to confirm water chemistry control. For simplicity, the subsequent tables (Table 2's) do not list the One-Time Inspection Program each time a water chemistry control program is listed. However, since the One-Time Inspection Program is applicable to each water chemistry control program, it is also applicable to each line item that credits a water chemistry control program.

To provide further clarification, the effectiveness of the Water Chemistry Control -

Auxiliary Systems, BWR, and Closed Cooling Water programs is confirmed by the One-Time Inspection program. This requires an amendment tothe license renewal application to change the Appendix A, SAR supplement descriptions for the Water Chemistry Control -Auxiliary Systems, BWR and Closed Cooling Water programs to explicitly state One-Time Inspection Program activities will confirm the effectiveness of these programs.

201 3.1.1-14-P-02 NUREG-1801 item IV.A1-8 specifies the water chemistry program for BWRs On page 3.1-53, the component type 'weld SLC nozzle to safe end weld (N10)' is augmented to verify program effectiveness by an inspection program such as the managed using BWR vessel internals, Water chemistry control - BWR. The AMP one-time inspection (OTI) program. The OTI program will be used to verify the applied, BWR VI, is acceptable, however, this differs from what is recommended by effectiveness of the water chemistry - BWR program wherever it is applied. Rather GALL. Please explain why Note E was not assigned. than list the OTI program every time the water chemistry - BWR program is listed in the 3.x.2 tables, the use of the OTI program is identified in the rollup (3.x.1) tables Edit from 5/11/2006 email - On page 3.1-53, the component type 'weld SLC nozzle to and in the further evaluation discussions. The use of the water chemistry - BWR safe end weld (N10)' is managed using BWR vessel internals, Water chemistry control program augmented by the OTI program is the basis for the use of Note A. Where BWR. Please explain how the BWR Vessel Internal program manage loss of material another program, such as the BWR vessel internals program could also be used to for SLC Nozzle to SE weld (N10) and provide either document or inspection plan to verify water chemistry program effectiveness, we have conservatively included it in support this AMR. the list of programs; however, it is considered a supplement to and not different from the NUREG-1 801 identified programs.

Revised Answer to Revised Question - The BWRVIP augments the ISI Program for weld N10-SE, the SLC (N10) safe end to vessel weld. The VYNPS inspection requirements for this weld are thus in PP 7027, "Reactor Vessel Internals Management Program." The SLC nozzle to safe end weld examination schedule and history is discussed in detail in section 15.0 of Appendix B to PP 7027.

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Item Request ResDonse 202 3.1.1-17-P-01 RAI 3.1.1-17-P-01

[Original Question]

On page 3.1-39, the component type 'reactor vessel shell, intermediate beltline shell' is [Original Response]

managed using reactor vessel surveillance and TLAA - neutron fluence. Please confirm As stated in LRA Section 4.2.1, there are no nozzles in the vertical section of the that the neutron fluence at the LPCI and RHR injection nozzle will remain <1 E17 n/cm2 reactor vessel ID that will receive greater than 1E17 n/cm2 (E > 1 MeV) during the (E>1 MeV) through the end of the period of extended operation. period of extended operation.

[Follow-up Question] [Follow-up Response]

In view of the power uprate, and based upon the graphic provided in GE-NE-0000-0014- VYNPS extrapolated the fluence near the recirculation inlet nozzles from known data 0292-01, "Vermont Yankee Nuclear Power Station Extended Power Uprate RPV Flux as follows.

Evaluation," fluence at the nozzle appears to be very close to lx1017 n/cm2. Please provide a calculation of the flux at the edge of the nozzle closest to the active fuel From drawing 104R940, the top of the nozzles is 202 inches.

region.

The fluence versus height is given in GE-NE-0000-0007-2342-R1-NP, figure 6-1.

This curve was ratioed to account for the power increase to 1912 MWt. This resulted in an ID surface fluence of 1El 7 at 204 inches, missing the nozzles by 2 inches. The adjustments to RTNDT and USE are based on 'A T fluence. The surface fluence is 35% higher than the 'A T fluence. The point at which the 'A T fluence exceeds 1E17 is approximately the bottom of the active fuel, 5.5 inches above the nozzle. The peak fluence values were calculated in accordance with Regulatory Guide 1.90 (See LRA section 4.2.1) and include conservatisms to ensure they are maximum values. Given these factors, the recirculation inlet nozzles do not exceed the 1E17 threshold for neutron embrittlement.

Even if the fluence at the nozzle slightly exceeds 1 E17 threshold, the correction factors from Regulatory Guide 1.99 are very small when just above the limit. (The RTNDT fluence factor is only 0.11 at 1E17. The curves for calculating the decrease in USE don't start till fluence reaches 1 E18; the formulas for the curves predict about 6% reduction in USE at 1El 7.)

Furhter details and RAI response provided in VYNPS Letter to NRC BVY 06-083 203 3.1.1-19-P-01 LRA Amendment On page 3.1-67, the component type 'piping and fittings <4" NPS' is managed using water chemistry control - BWR, One-time inspection. The GALL suggests that a plant- All piping and fittings less than 4" NPS, except for the head seal leak detection line, specific program is appropriate for managing SCC of these components. Please identify are covered by NUREG-1801 item IV.C1-1, which identifies ISI, water chemistry for the inspection techniques that are to be used and the basis for concluding that one-time BWRs and one-time inspection (OTI) for small bore piping as the applicable aging inspection is appropriate, rather than periodic inspection. management programs for cracking. The VYNPS ISI program includes piping and fittings less than 4" NPS. The LRA will be clarified to indicate that ISI in addition to Edit from 5/11/2006 - On page 3.1-67, the component type 'piping and fittings <4" NPS' water chemistry control - BWR and OTI applies to these components.

is managed using water chemistry control - BWR, One-time inspection. Why VY does not credit ISI program?

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Item Request Response 204 3.1.1-29-P-01 LR Commitment 37 On page 3.1-62, the component type 'steam dryers' is managed using BWR vessel internals. The AMR indicates that cracking of the steam dryers will be managed using VYNPS submitted a steam dryer monitoring plan as part of the recent power uprate the BWR VI program, yet they are not listed in the scope of the program. Please application. That plan was approved by the NRC. That plan will continue dryer provide a plant-specific AMP as recommended by GALL or ensure that each of the 10 inspections for at least three consecutive refueling outages after the power uprate.

attributes of an acceptable management program are to be addressed.

BWRVIP-139, Steam Dryer Inspection and Flaw Evaluation Guidelines, has been submitted to the NRC for review and approval. This BWRVIP document is expected to be approved by the NRC prior to the period of extended operation and as such will become a part of the BWR Vessel Internals Program. The VYNPS vessel internals procedure commits VY to comply with every approved BWRVIP. As such, VYNPS will manage cracking of the steam dryers per the BWR Vessel Internals Program during the period of extended operation.

In the unlikely event that BWRVIP-1 39 is not approved prior to the period of extended operation, VYNPS will continue inspections in accordance with the Steam Dryer Monitoring Program, Revision 3, as previously approved by the NRC as part of the Extended Power Uprate. These inspections will be in accordance with the guidance in SIL 644, Rev. 1.

Commitment #37 will state the following:

Continue inspections in accordance with the Steam Dryer Monitoring Program, Revision 3 in the event that the BWRVIP-139 is not approved prior to the period of extended operation.

205 3.1.1-40-P-01 Although Item IV.A1-5 lists the BWR Penetrations program for cracking, the On page 3.1-40, the component type 'CRD stub tubes' is managed using BWR Vessel program description in NUREG-1 801 Chapter Xl does not include the CRD stub Internals, water chemistry control - BWR. For this item, GALL recommends the use of tubes are in the program scope. The BWR Vessel Internals program does not a program consistent with XI.M8, "BWR Penetrations." No exception was taken to the specifically address the CRD stub tubes either, but is a more appropriate aging scope of VYNPS AMP B.1.4, "BWR Penetrations Program. It would also seem management program for this particular component. Note E is assigned to this line appropriate to assign Note E to this item unless the AMP assigned is changed. since the program does not match that listed in the NUREG-1 801 item.

206 3.1.1-40-P-02 Inservice inspection (ISI) and water chemistry - BWR are listed for the management On page 3.1-41, the component type 'incore housings' is managed using inservice of both loss of material and cracking. The listed NUREG-1801 item is correct for inspection, water chemistry control - BWR. Please confirm that the correct GALL item both aging effects. For loss of material, the water chemistry - BWR and one-time is referenced. inspection programs (see response to question 3.1.1-14-P-02 for discussion on OTI program applicability) are the basis for the use of Note A, and the ISI program is supplemental. For cracking, Note E is used since the ISI program is different from the program (BWR Penetrations) listed in NUREG-1801.

207 3.1.1-41-P-01 The BWR Stress Corrosion Cracking Program (GALL Section XI.M7) is designed for On page 3.1-72, the component type 'restrictors (ms)' is managed using water pressure boundary piping. The main steam flow restrictors are not pressure chemistry control - BWR, One-time inspection. Please provide the basis for excluding boundary components. As such they are not subject to ASME inspection this component from the BWR Stress Corrosion Cracking program. requirements and were not a good fit for the BWRSCC program. VYNPS opted to manage them by One Time Inspection.

Edit from 5/11/2006 email - On page 3.1-72, the component type 'restrictors (ms)' is managed using water chemistry control - BWR, One-time inspection. Please provide the basis for excluding this component from the BWR Stress Corrosion Cracking program. Is restrictor (ms) weld inspection part of ISI also?

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Item Request Response 208 3.1.1-41-P-02 The material for these components is identified as low allow steel with. stainless On page 3.1-41, the component type 'nozzles recirc outlets (N1), recirc inlets (N2)' and steel cladding. The material exposed to the internal environment of reactor coolant on page 3.1-43, the component type 'nozzles, cote spray (N5), head spray (N6A), head (treated water) is the stainless steel cladding. When evaluating surface aging instrumentation (N6B), head vent (N7), jet pump instrumentation (N8)' are managed effects such as cracking and loss of material, the stainless-steel cladding is the using inservice inspection, water chemistry control - BWR. The GALL item referenced material that must match the NUREG-1801 item. NUREG-1801 item IV.A1-1 in this AMR is for Stainless steel and nickel-based alloy components that may be provides the best match for the material, environment and aging effect combination subject to SCC. It does not appear to be appropriate for low-alloy steel. Please Identify within the BWR reactor vessel table.

a more suitable GALL item.

The applicable material for the external environment (air) is low alloy steel (or "steel" in NUREG-1801 terms).

209 3.1.1-41-P-03 LRA Amendment On page 3.1-45, the component type 'nozzles flange leak-off (N13, N14)'; on page 3.1-47, the component type 'flanges, head nozzle flanges (N6, N7), blank flanges (N6)'; on The BWRSCC program (GALL Section XI.M7) applies to stainless steel piping >=4" page 3.1-51, the component type 'safe ends < 4" core SCL/?P (N10), instrumentation in diameter. N13 and N14 are 2" nozzles. Safe ends <4" N10 is a 2" safe end. N11 (N11, N12)'; and on page 3.1-52, the component type 'thermal sleeves, feedwater and N12 are 2" nozzles.

inlets (N4)' are managed using inservice inspection, water chemistry control - BWR. N6 and N7 are low alloy steel and thus not susceptible to IGSCC. N6 blank flanges Please explain why these are not managed using the BWR SCC program. are 6" stainless steel flanges. These flanges were included in the ISI Program with the rest of the nozzle assembly.

Edit from 5/11/2006 email - on page 3.1-47, the component type 'flanges, head nozzle The feedwater thermal sleeves (N4) are a combination of stainless steel and nickel-flanges (N6, N7), blank flanges (N6)'; instrumentation (NIl, N12)'; and on page 3.1-52, based alloy in a 10 inch nozzle. The BWRSCC program in NUREG-1801 does not the component type 'thermal sleeves , feedwater inlets (N4)' are managed using appear to include feedwater thermal sleeves. Therefore, the feedwater thermal inservice inspection, water chemistry control - BWR. Please confirm these nozzles are sleeves were included in the ISI and water chemistry control programs.

less than 4 NPS. Please clarify how to manage feedwater inlets thermal sleeve with ISI The status of the feedwater thermal sleeves has already been given in response to program. question 291. That response is reproduced below.

The feedwater nozzle thermal sleeves are in Table 3.1.2-1 with an intended function of pressure boundary. Cracking of the thermal sleeves is managed by Inservice Inspection and Water Chemistry Control - BWR.

Further review of the thermal sleeve design (to determine exactly how ISI inspects them) determined that the VY sleeves are not welded in place; rather they are an interference fit. As such, there is no weld to the pressure boundary piping that can be examined by ISI.

Given that there is no pressure boundary weld, these sleeves are not part of the pressure boundary. As such they have no intended function for license renewal, and with no intended function they are not subject to aging management review1.

Therefore, Vermont Yankee will amend the license renewal application to indicate that the feedwater thermal sleeves are not subject to aging management review.

The feedwater thermal sleeves have no non-safety affecting safety related (a2) function. They are completely contained within the feedwater piping and cannot spray or leak on other equipment. The feedwater thermal sleeves are a part of the feedwater piping inside the vessel, and failure of that piping does not defeat the delivery of water to the vessel annulus, as any leakage also goes to the vessel annulus.

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Item Request ResDonse 210 3.1.1-43-P-01 The matching of component types between the plant and NUREG-1801 is not On page 3.1-56, the component type 'control rod guide tubes, bases' is managed using always straightforward. Minor differences in component names (as in this example)

BWR vessel internals, water chemistry control - BWR. The component type appears to can lead to uncertainty in the intended scope of components in the NUREG-1 801 be described by the structure and/or component column in GALL Table IV.B1. Please item. Our approach was to err conservatively, so Notes C and D were sometimes clarify the basis for assigning Note D. used where Notes A and B might have been acceptable. Since the comparison is equally valid with either set of notes, this conservative approach is considered appropriate.

211 3.1.1-44-P-01 The recirc inlet thermal sleeve is a match for the jet pump assembly thermal sleeve On page 3.1-52, the component type 'thermal sleeves recirc inlet (N2) core spray (N5)' in NUREG-1801 item IV.B1-13, so Note B could be applied to that portion of this line is managed using BWR vessel internals and water chemistry control - BWR. Please for cracking. However, the core spray thermal sleeve does not match and Note D confirm that for the recirc inlet nozzle thermal sleeve, Note B would apply. was selected to conservatively cover both component types. As described in the response to question 3.1.1-43-P-01, the comparison is equally valid with the Edit from 5/11/2006 email - On page 3.1-52, the component type 'thermal sleeves recirc selection of either Note B or D.

inlet (N2) core spray (N5)' is managed using BWR vessel internals and water chemistry control - BWR. Please confirm that for the recirc inlet nozzle thermal sleeve, Note B Revised Answer to Revised Question - The recirc inlet thermal sleeve is a match for would apply. Please clarify how BWR Vessel Internal Program manages recirc inlet the jet pump assembly thermal sleeve in NUREG-1 801 item IV.B1 -13, so Note B thermal sleeves. could be applied to that portion of this line for cracking. However, the core spray thermal sleeve does not match and Note D was selected to conservatively cover both component types. NUREG-1801 Item IV.B1-7 could also have been referenced for the core spray thermal sleeve with a Note B and credit for the same programs. As described in the response to question 3.1.1-43-P-01, the comparison is equally valid with the selection of either Note B or D.

Appendix B of the application identifies some exceptions to the NUREG-1 801 description of the BWR Vessel Internals Program; however, none of these exceptions are related to the recirc inlet (jet pump assembly) thermal sleeve. The VYNPS BWR Vessel Internals Program management of cracking for the recirc inlet thermal sleeve is consistent with the NUREG-1801 program that is credited in Item IV.B1-13 for this component.

212 3.1.1-47-P-01 Page 3.1-56 is the beginning of the reactor vessel internals (Table 3.1.2-2). In In many cases (beginning on page 3.1-56), component types are managed using water general the reactor vessel internals are not code parts and are not included in the chemistry control - BWR and not the ISI program. Please provide the basis for Inservice Inspection Program. This is discussed in Item 3.1.1-47 in Table 3.1.1 of excluding them from the ISI program. the LRA.

Edit from 5/11/2006 email - In many cases (beginning on page 3.1-56), component Even in cases like the shroud support, where the components are considered code types are managed using water chemistry control - BWR alone for loss of material. parts, the BWRVIP provides the approved inspections for these components.

Please provide the basis for excluding them from the ISI program. Those inspections are implemented by augmenting the Inservice Inspection program, but the BWR Vessel Internals program is credited as the controlling program.

213 3.1.1-48-P-02 The One-Time Inspection Program as described in LRA Appendix B, Section B.1.21, On page 3.1-73, the component type 'tank (CRD accumulator)' is managed using water includes all piping and valves <4" NPS. The CRD accumulators are included in this chemistry control - BWR, One-time inspection. It is not clear that the tank is <NPS4, so program. While they are slightly larger than 4", they are connected to the RCS by ISI would seem a more appropriate AMP for verification (and a different GALL item may long runs of 1 inch piping and are therefore treated with that small bore piping.

be a more useful reference).

The CRD accumulators are not reactor coolant pressure boundary parts. Each drive has two accumulators, one of which is filled with nitrogen and the other with part nitrogen and part water. These components are not subject to ISI. Consequently, Water Chemistry Control augmented by One-Time Inspection is the best option.

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Item Request Response 214 3.1.1-48-P-03 The One-Time Inspection Program includes all piping and valves <4" NPS. The On page 3.1-63, the component type 'condensing chambers' is managed using water instrumentation condensing chambers on the main steam flow elements are chemistry control - BWR, One-time inspection. Please confirm that this component is included in this program. While they may be slightly larger than 4", they are

<NPS4 connected by 1 inch instrument piping and are treated with that small bore piping.

These chambers are not subject to other inspections such as ISI.

215 3.1.1-49-P-01 VY performed a VT in 1995 and 1996, a MVT1 in 1998, and an EVT1 in 1999 and On page 3.1-62, the component type 'shroud support, ring, cylinder, and legs, access 2002. Additional EVT1 inspections are scheduled for 2006 and 2009. [Appendix A hole cover' is managed using BWR vessel internals, water chemistry control - BWR. of PP 7027] The examination coverage includes the entire weld surface, in addition For the access hole cover plate, GALL recommends ISI and water Chemistry. Please to the heat-affected zones." [Sec 4.3 of NE 8067]

identify the specific inspection(s) for this component under the RVI program.

Section 4.3 of NE 8067 is reproduced below. It requires that the access hole covers Extended question from meeting on 6/27/06: VY credits the BWR vessel internals be examined by EVT-1.

program for managing the access hole covers, but the NRC is not aware of any BWRVIP document that addresses the access hole covers. Please clarify how VYNPS 4.3 Access Hole Cover Welds - The access hole cover welds shall be examined by manages the access hole covers. the EVT 1 method.

There are two oval access hole cover welds, located at 0 and 180 degrees. They are designated as 0-AHC and 180-AHC. The GTAW portion is Inconel Alloy 82 and the SMAW portion is Inconel Alloy 182. Note that because these are nickel based welds, the required examination coverage includes the entire weld surface, in addition to the heat affected zones.

See drawing 5920 253 216 3.1.1-50-P-01 LR Commitment 34 On page 3.1-36, the component type 'other pressure boundary bolting, flange bolts and LRA Amendment nuts (N6A, N6B, N7), CRD flange cap-screws and washers' is managed using inservice inspection. Please confirm that the new Bolting Integrity AMP will be applied to this The Inservice Inspection program is used to manage cracking of this Class 1 bolting item, and identify a more appropriate GALL item. since these components are required to be inspected in accordance with ASME Section Xl IWB requirements. A Bolting Integrity Program is under development (commitment #34) that will address the aging management of bolting in the scope of license renewal including the bolting identified in this line item. The GALL Bolting Integrity Program XI.M1 8 states that the ASME Section Xl Inservice Inspection Program XI.M1 supplements the Bolting Integrity Program. GALL line item (IV.A1-9) identified in the LRA for comparison is for BWR high-strength low-alloy steel closure studs and nuts exposed to air with an aging effect of cracking. A review of GALL Chapter IV identified no other BWR closure bolting line items exposed to air with cracking as an aging effect. Therefore this line item was selected as the appropriate comparison and will remain the appropriate comparison with the inclusion of the Bolting Integrity Program.

Bolting Integrity Program Descriptions are provided in LRA Amendments 16 and 23.

217 3.1.1-51-P-01 NUREG-1801 item IV.B1-1 1 also applies. The resulting note would be Note A.

On page 3.1-60, the component type 'jet pump castings, transition piece inlet elbow/

nozzle, mixer flange and flare, diffuser collar' is managed using thermal aging embrittlement of CASS. Please confirm that IV.B1-11 also applies.

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Item Request Response 218 3.1.1-52-P-01 LR Commitment 34 On page 3.1-36, the component type 'incore housing bolting, flange bolts, flange nut LRA Amendment and washer' is managed using inservice inspection. Please confirm that the new Bolting Integrity AMP will be applied to this item, and identify a more appropriate GALL Revised answer for 5/11/2006 email - A Bolting Integrity Program is under item. development (commitment #34) that will address the aging management of bolting in the scope of license renewal including the bolting identified in this line item. In addition, the Inservice Inspection Program is used to manage cracking of this Class 1 bolting since these components are required to be inspected in accordance with ASME section Xl IWB requirements. The GALL Bolting Integrity Program XI.M18 states that the ASME Section Xl Inservice Inspection Program XI.M1 supplements the Bolting Integrity Program. The GALL line item (IV.A2-6) identified in the LRA for comparison is for stainless steel flange bolting exposed to air with an aging effect of cracking. A review of GALL Chapter IV identified no BWR stainless steel bolting line items exposed to air with cracking as an aging effect. Therefore this line item was selected as the appropriate comparison.

A Bolting Integrity Program is under development that will address the aging management of bolting in the scope of license renewal including the bolting identified in this line item. The Inservice Inspection program is used to manage cracking of this Class 1 bolting since these components are required to be inspected in accordance with ASME section XI IWB requirements. The GALL Bolting Integrity Program XI.M18 states that the ASME Section XI Inservice Inspection Program XI.M1 supplements the Bolting Integrity Program. The GALL line item (IV.A2-6) identified in the LRA for comparison is for stainless steel flange bolting exposed to air with an aging effect of cracking. A review of GALL Chapter IV identified no BWR stainless steel bolting line items exposed to air with cracking as an aging effect.

Therefore this line item was selected as the appropriate comparison and will remain the appropriate comparison with the inclusion of the Bolting Integrity Program.-

Bolting Integrity Program Descriptions are provided in LRA Amendments 16 and 23.

219 3.1.1-55-P-01 Pump casing and cover - The VYNPS ISI program is a plant-specific program, not On page 3.1-71, the component type 'pump casing and cover (RR)' is managed using compared to the GALL XI.M1 program. Therefore, Note E was applied wherever the inservice inspection. On page 3.1-75, the component type 'valve bodies <4" NPS' is ISI program was called for in GALL. Note that earlier on this same page, WCC and managed using one-time inspection. On page 3.1-79, the component type 'valve ISI are used to manage loss of material and Note A is used - that is because GALL bodies >=4" NPS' is managed using inservice inspection. Please clarify the basis, in only requires water chemistry and the use of IS[ here is over and above what GALL each case, for asserting that the AMP used is different from the one suggested by requires.

GALL.

For valve bodies <4" NPS - GALL manages reduction of fracture toughness (ROFT) using ISI, however, ISI only requires inspections of valves bodies >=4" NPS.

Therefore, the OTI (small bore piping) program is used to mange ROFT for these small valves.

Valve bodies >=4" NPS - The VYNPS ISI program is a plant specific program, not compared to the GALL XI.M1 program. Therefore, VYNPS applied Note E wherever the ISI program was identified in GALL.

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Item Request Response 220 3.1.1-57-P-01 GALL program XI.M12 is applicable to "primary pressure boundary and reactor On page 3.1-72, the component type 'restrictors (ms)' is managed using one-time vessel intemals components' and the main steam flow restrictors are neither. As inspection. Please describe how OTI satisfies the recommendations of GALL AMP the main steam flow restrictors are not ASME pressure boundary components, XI.M12, Thermal Aging Embrittlement of CASS. program XI.M12 is not applicable. Thermal aging embrittlement results in increased rates of crack growth, which are evidenced by cracking in the material. The One-Time Inspection Program will be used to Verify that reduction of fracture toughness has not progressed to the point that unacceptable cracking of the component has occurred.

221 3.3.1-03-K-01 As stated in LRA Section 3.3.2.2.2, reduction of heat transfer due to fouling for On page 3.3-91, the component type 'heat exchanger (tubes)' is managed using water stainless steel heat exchanger tubes exposed to treated water is managed by the chemistry control - BWR. Please confirm that the VYNPS Water Chemistry - BWR Water Chemistry Control - BWR Program. The effectiveness of the Water AMP addresses fouling in heat exchanger tubes. Chemistry Control-BWR Program will be confirmed by the One-Time Inspection Program through an inspection of a representative sample of components crediting this program including areas of stagnant flow.

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Item Request Resnonse 222 3.3.1-05-K-01 SRP-LR Appendix Al is applicable to purely preventive programs. In fact, Section On page 3.3-74, the component type 'heat exchanger (tubes) ' is managed using water A.1.2.3.3, Item 4, states, "For prevention and mitigation programs, the parameters chemistry control - BWR. GALL recommends a plant-specific program. Please clarify monitored should be the specific parameters being controlled to achieve prevention how each of the attributes of SRP-LR Appendix Al is addressed by a purely preventive or mitigation of aging effects. An example is the coolant oxygen level that is being program. controlled in a water chemistry program to mitigate pipe cracking."

Edit from 5/11/2006 email - On page 3.3-74, the component type 'heat exchanger As stated in LRA Section B.1.30.2, the Water Chemistry Control - BWR Program is (tubes)'is managed using water chemistry control - BWR. GALL recommends a plant- consistent with the program described in NUREG-1 801,Section XI.M2, "Water specific program. Please clarify how this component is addressed by a purely Chemistry." The One-Time Inspection Program, described in LRA Section B.1.21 preventive program. includes inspections to verify the effectiveness of the water chemistry control aging management programs (Water Chemistry Control - Auxiliary Systems, Water Chemistry Control - BWR, and Water Chemistry Control - Closed Cooling Water) by confirming that unacceptable cracking, loss of material, and fouling is not occurring. As stated in LRA Section B.1.21, the One-Time Inspection Program is a new program which will be consistent with the program described in NUREG-1 801,Section XI.M32, "One-Time Inspection."

The 10 attributes of SRP-LR Appendix Al for the Water Chemistry Control - BWR Program and the One-Time Inspection Program are the same as the attributes of the NUREG-1801 programs XI.M2 and XI.M32.

Added Response to 5/11/2006 email -

Page 3.3-74 has multiple line items for heat exchanger (tubes) managed using Water Chemistry Control - BWR. The response assumes this question refers to the line item for cracking of heat exchanger (tubes) since this line item references NUREG-1801 item VII.E3-3 which recommends a plant-specific program.

As stated in LRA Section B.1.30.2, the Water Chemistry Control - BWR Program optimizes the primary water chemistry to minimize the potential for loss of material and cracking. This is accomplished by limiting the levels of contaminants in the RCS that could cause loss of material and cracking. Additionally, VYNPS has instituted hydrogen water chemistry (HWC) with noble metals to limit the potential for intergranular SCC (IGSCC) through the reduction of dissolved oxygen in the treated water is consistent with the program described in NUREG-1801,Section XI.M2, "Water Chemistry." The One-Time Inspection Program, described in LRA Section B.1.21 includes inspections to verify the effectiveness of the water chemistry control aging management programs (Water Chemistry Control - Auxiliary Systems, Water Chemistry Control - BWR, and Water Chemistry Control - Closed Cooling Water) by confirming that unacceptable cracking, loss of material, and fouling is not occurring.

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Item Reauest ResDonse 223 3.3.1-13-K-01 Page 3.3-92 has multiple line items for neutron absorber (boral) managed using On page 3.3-92, the component type 'neutron absorber (boral)' is managed using water Water Chemistry Control - BWR. The response assumes this question refers to the chemistry control - BWR. GALL recommends a plant-specific program. Please clarify line item for loss of material for neutron absorber (boral) since this line item how each of the attributes of SRP-LR Appendix Al is addressed by a purely preventive references NUREG-1801 item VII.A2-3 which recommends a plant-specific program.

program.

SRP-LR Appendix Al is applicable to purely preventive programs. In fact, Section Edit from 5/11/2006 email - On page 3.3-92, the component type 'neutron absorber A.1.2.3.3, Item 4, states, "For prevention and mitigation programs, the parameters (boral)' is managed using water chemistry control - BWR. GALL recommends a plant- monitored should be the specific parameters being controlled to achieve prevention specific program. Please clarify how this component is addressed by a purely or mitigation of aging effects. An example is the coolant oxygen level that is being preventive program. controlled in a water chemistry program to mitigate pipe cracking."

As stated in LRA Section B.1.30.2, the Water Chemistry Control - BWR Program is consistent with the program described in NUREG-1801,Section XI.M2, "Water-Chemistry." The One-Time Inspection Program, described in LRA Section B.1.21 includes inspections to verify the effectiveness of the water chemistry control aging management programs (Water Chemistry Control - Auxiliary Systems, Water Chemistry Control - BWR, and Water Chemistry Control - Closed Cooling Water) by confirming that unacceptable cracking, loss of material, and fouling is not occurring. As stated in LRA Section B.1.21, the One-Time Inspection Program is a new program which will be consistent with the program described in NUREG-1 801,Section XI.M32, "One-Time Inspection."

The 10 attributes of SRP-LR Appendix Al for the Water Chemistry Control - BWR Program and the One-Time Inspection Program are the same as the attributes of the NUREG-1 801 programs XI.M2 and XI.M32.

Added Response per 5/11/2006 email As stated in LRA Section B.1.30.2, the Water Chemistry Control - BWR Program optimizes the primary water chemistry to minimize the potential for loss of material and cracking. This is accomplished by limiting the levels of contaminants in the RCS that could cause loss of material and cracking. Additionally, VYNPS has instituted hydrogen water chemistry (HWC) with noble metals to limit the potential for intergranular SCC (IGSCC) through the reduction of dissolved oxygen in the treated water is consistent with the program described in NUREG-1 801,Section XI.M2, "Water Chemistry." The One-Time Inspection Program, described in LRA Section B.1.21 includes inspections to verify the effectiveness of the water chemistry control aging management programs (Water Chemistry Control - Auxiliary Systems, Water Chemistry Control - BWR, and Water Chemistry Control - Closed Cooling Water) by confirming that unacceptable cracking, loss of material, and fouling is not occurring.

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Item Request Response 224 3.3.1-14-K-01 LRA Amendment In many cases, beginning on page 3.3-61 for auxiliary systems, component types exposed to oil are managed using the oil analysis program. Please confirm that the As stated in LRA Section 3.2.2.7, steel piping and components in auxiliary systems VYNPS Oil Analysis AMP is consistent with GALL XI.M32, "One-Time Inspection," as at VYNPS that are exposed to lubricating oil are managed by the Oil Analysis well as with XI.M39, "Lubricating Oil Analysis." Program, which includes periodic sampling and analysis of lubricating oil to maintain contaminants within acceptable limits, thereby preserving an environment that is not conducive to corrosion. As stated in LRA Section B.1.20, the Oil Analysis Program is consistent with the program described in NUREG-1801,Section XI.M39, Lubricating Oil Analysis, with a minor exception.

The Oil Analysis Program is not consistent with GALL XI.M32, "One-Time Inspection," nor are one-time inspections necessary to verify the effectiveness of the program. Metals are not corroded by the hydrocarbon components of lubricants.

Lubricating oils are not good electrolytes and the oil film on the wetted surfaces of components tend to minimize the potential for corrosion. Corrosion in lube oil systems only occurs as the result of the presence of impurities or moisture.

Therefore, an effective oil analysis program, which maintains impurities and moisture below specified limits, precludes the need for one-time inspections.

Operating experience at VYNPS has confirmed the effectiveness of the Oil Analysis Program in maintaining moisture and impurities within limits such that corrosion has not and will not affect the intended functions of these components.

In numerous past precedents (including NUREG-1828, Arkansas Nuclear One Unit 2 SER, Section 3.0.3.3.6, and NUREG-1831, Donald C. Cook SER, Section 3.0.3.3.8), the staff concluded that an effective oil analysis program, which '

maintains impurities and moisture below specified limits, is sufficient to demonstrate that the effects of aging will be adequately managed so that the intended functions will be maintained consistent with the current licensing basis for the period of extended operation.

The One-Time Inspection program will be revised to include activities to confirm the effectiveness of the Oil Analysis and Diesel Fuel Monitoring programs.

~ ~.. ' ,.- ',rt-'rr,'.~,'rr. -rrr~4r~.,,r ... - ',~'-~rr--r ~ Page 72 of 150

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Item Request Response 225 3.3.1-20-K-01 LRA Amendment

.Beginning on page 3.3-166, many component types are managed using the diesel fuel monitoring program. Please confirm that the VYNPS Diesel Fuel Monitoring AMP is As stated in LRA Section 3.2.2.9, loss of material dueto general, pitting, crevice, consistent with GALL XI.M32, "One-Time Inspection," as well as with XI.M30, "Fuel Oil and MIC for carbon steel piping and components exposed to fuel oil is managed by Chemistry." the Diesel Fuel Monitoring Program. This program includes sampling and monitoring of fuel oil quality to ensure levels of water, particulates, and sediment remain within the specified limits. Maintaining parameters within limits ensures that significant loss of material will not occur. Ultrasonic inspection of storage tank bottoms where water and contaminants accumulate will be performed to confirm the effectiveness of the Diesel Fuel Monitoring Program. As stated in LRA Section B.1.9, the Diesel Fuel Monitoring Program is consistent with the program described in NUREG-1801,Section XI.M3, Fuel Oil Chemistry Program, with minor exceptions.

The Diesel Fuel Monitoring Program is not consistent with GALL XI.M32, "One-Time Inspection," nor are one-time inspections necessary to verify the effectiveness of the program. The Diesel Fuel Monitoring Program includes periodic cleaning, visual inspection, and ultrasonic inspection of storage tank bottoms where water and contaminants accumulate to confirm the effectiveness of the oil quality monitoring activities to preserve an environment that is not conducive to corrosion The One-Time Inspection program will be revised to include activities to confirm the effectiveness of the Oil Analysis and Diesel Fuel Monitoring programs.

This requires and amendment to the LRA.

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Item Request Response 226 3.3.1-21 -K-01 LRA Amendment On page 3.3-106, the component type 'heat exchanger (bonnet)'; on page 3.3-141, the component type 'heat exchanger (shell)'; and on page 3.3-78, the component type 'heat As stated in LRA Section 3.2.2.7, steel piping and components in auxiliary systems exchanger (shell)' are managed using the oil analysis program. Please confirm that the at VYNPS that are exposed to lubricating oil are managed by the Oil Analysis VYNPS Oil Analysis AMP is consistent with GALL XI.M32, "One-Time Inspection," as Program, which includes periodic sampling and analysis of lubricating oil to maintain well as with XI.M39, "Lubricating Oil Analysis." contaminants within acceptable limits, thereby preserving an environment that is not conducive to corrosion. As stated in LRA Section 6.1.20, the Oil Analysis Program is consistent with the program described in NUREG-1801,Section XI.M39, Lubricating Oil Analysis, with a minor exception.

The Oil Analysis Program is not consistent with GALL XI.M32, "One-Time Inspection," nor are one-time inspections necessary to verify the effectiveness of the program. Metals are not corroded by the hydrocarbon components of lubricants.

Lubricating oils are not good electrolytes and the oil film on the wetted surfaces of components tends to minimize the potential for corrosion. Corrosion in lube oil systems only occurs as the result of the presence of impurities or moisture.

Therefore, an effective oil analysis program, which maintains impurities and moisture below specified limits, precludes the need for one-time inspections.

Operating experience at VYNPS has confirmed the effectiveness of the Oil Analysis Program in maintaining moisture and impurities within limits such that corrosion has not and will not affect the intended functions of these components.

In numerous past precedents (including NUREG-1828, Arkansas Nuclear One Unit 2 SER, Section 3.0.3.3.6, and NUREG-1831, Donald C. Cook SER, Section 3.0.3.3.8), the staff concluded that an effective oil analysis program, which maintains impurities and moisture below specified limits, is sufficient to demonstrate that the effects of aging will be adequately managed so that the intended functions will be maintained consistent with the current licensing basis for the period of extended operation.

The One-Time Inspection program will be revised to include activities to confirm the effectiveness of the Oil Analysis and Diesel Fuel Monitoring programs.

111/071... PM **. Page.74.of"150*...

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Item Request Response 227 3.3.1-23-K-01 LRA Amendment Beginning on page 3.3-221, component types exposed to treated water are managed using water chemistry control - BWR. Please confirm that the VYNPS Water As stated in LRA Section B.1.30.2, the Water Chemistry Control - BWR Program is Chemistry - BWR AMP is consistent with GALL XI.M32, "One-Time Inspection," as well consistent with the program described in NUREG-1801,Section XI.M2, "Water as with XI.M2, "Water Chemistry." Chemistry." The One-Time Inspection Program, described in LRA Section B.1.21 includes inspections to verify the effectiveness of the water chemistry control aging management programs (Water Chemistry Control - Auxiliary Systems, Water Chemistry Control - BWR, and Water Chemistry Control - Closed Cooling Water) by confirming that unacceptable cracking, loss of material, and fouling is not occurring. As stated in LRA Section B.1.21, the One-Time Inspection Program is a new program which will be consistent with the program described in NUREG-1801,Section XI.M32, "One-Time Inspection."

LRA Tables 3.1.1, 3.2.1, 3.3.1, and 3.4.1 indicate that the One-Time Inspection Program is credited along with the water chemistry control programs for line items for which GALL recommends a one-time inspection to confirm water chemistry control. For simplicity, the subsequent tables (Table 2's) do not list the One-Time Inspection Program each time a water chemistry control program is listed. However, since the One-Time Inspection Program is applicable to each water chemistry control program, it is also applicable to each line item that credits a water chemistry control program.

To provide further clarification, the effectiveness of the Water Chemistry Control -

Auxiliary Systems, BWR, and Closed Cooling Water programs is confirmed by the One-Time Inspection program. This requires an amendment to the license renewal application to change the Appendix A, SAR supplement descriptions for the Water Chemistry Control -Auxiliary Systems, BWR and Closed Cooling Water programs to explicitly state One-Time Inspection Program activities will confirm the effectiveness of these programs.

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Item Request Resnonse 228 3.3.1-25-K-01 Page 3.3-129 has multiple line items for heat exchanger (tubes) managed using On page 3.3-65, the component type 'heat exchanger (tubes)' and on page 3.3-129, the Service Water Integrity. The response assumes this question refers to the line item component type 'heat exchanger (tubes)' are managed using service water integrity. for loss of material for heat exchanger (tubes) exposed to external condensation GALL recommends a plant-specific program. Please clarify how each of the attributes managed using Service Water Integrity since this line item matches the line item on of SRP-LR Appendix Al is to be addressed for this item. page 3.3-65 for heat exchanger (tubes) managed using Service Water Integrity.

Edit from 5/11/2006 email - On page 3.3-65, the component type 'heat exchanger These line items are for reactor building recirculation unit coolers, which are (tubes)' and on page 3.3-129, the component type 'heat exchanger (tubes)' are enclosed housing air-handling units with copper cooling coils (tubes). Raw water managed using service water integrity. GALL recommends a plant-specific program. flows through the copper tubes, while external surfaces of the tubes are exposed to Please clarify how service water integrity program manages this item. condensation.

Consistent with NUREG-1801 line item VII.C1-3, loss of material on the internal surfaces of these copper heat exchanger tubes is managed by the Service Water Integrity Program. The Service Water Integrity Program, in accordance with NRC GL 89-13, includes a condition and performance monitoring program which inspects components for erosion, corrosion, and blockage and verifies the heat transfer capability of safety-related heat exchangers cooled by service water. Therefore, this program is equally as effective at managing loss of material on the external surfaces of the heat exchanger tubes as it is at managing loss of material on the internal surfaces of the tubes. However, the line items in question were compared with NUREG 1801 item VII.F1-16 (which recommends a plant-specific program) because NUREG 1801 Section VII.C1 does not address the external surfaces of copper alloy heat exchanger tubes containing raw water.

As stated in LRA Section B.1.26, the Service Water Integrity Program is consistent with the program described in NUREG-1801,Section XI.M20, "Open-Cycle Cooling Water System," with minor exceptions.

The 10 attributes of SRP-LR Appendix Al for the Service Water Integrity Program are described in the Aging Management Program Evaluation Results (AMPER)

Report, which is available for on-site review.

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Item Request Response 229 3.3.1-26-K-01 LRA Amendment Beginning on page 3.3-80, the components exposed to fuel oil are managed using the oil analysis program. Please confirm that the VYNPS Diesel Fuel Monitoring AMP is As stated in LRA Section 3.2.2.9, loss of material due to general, pitting, crevice, consistent with GALL XI.M32, "One-Time Inspection," as well as with XI.M30, "Fuel Oil and MIC for carbon steel piping and components exposed to fuel oil is managed by Chemistry." the Diesel Fuel Monitoring Program. This program includes sampling and monitoring oi luel oil quality to ensuTe levels of water, particulates, and sediment Edit from 5/11/2006 email - Beginning on page 3.3-80, the components exposed to lube remain within the specified limits. Maintaining parameters within limits ensures that oil are managed using the Oil Analysis program. Please confirm that the VYNPS Oil significant loss of material will not occur. Ultrasonic inspection of storage tank Analysis AMP is consistent with bottoms where water and contaminants accumulate will be performed to confirm the GALL XI.M32, "One-Time Inspection," as well as with XI.M39, "Lube Oil Chemistry." effectiveness of the Diesel Fuel Monitoring Program. As stated in LRA Section B.1.9, the Diesel Fuel Monitoring Program is consistent with the program described in NUREG-1801,Section XI.M3, Fuel Oil Chemistry Program, with minor exceptions.

The Diesel Fuel Monitoring Program is not consistent with GALL XI.M32, "One-Time Inspection," nor are one-time inspections necessary to verify the effectiveness of the program. The Diesel Fuel Monitoring Program includes periodic cleaning, visual inspection, and ultrasonic inspection of storage tank bottoms where water and contaminants accumulate to confirm the effectiveness of the oil quality monitoring activities to preserve an environment that is not conducive to corrosion.

The One-Time Inspection program will be revised to include activities to confirm the effectiveness of the Oil Analysis and Diesel Fuel Monitoring programs.

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Item Request ResDonse 230 3.3.1-27-K-01 Page 3.3-69 has multiple line items for suction barrel managed using Service Water On page 3.3-69, the component type 'suction barrel' is managed using service water Integrity. The response assumes this question refers to the line item for loss of integrity. GALL recommends a plant-specific program. Please clarify how each of the material for suction barrel with an external environment of condensation since this attributes of SRP-LR Appendix Al is addressed for this item. line item references NUREG-1801 item VII.F1-1 which recommends a plant-specific program.

These line items are for residual heat removal service water pump suction barrels which are made of AL6XN which is a type of stainless steel that is highly resistant to corrosion. The suction barrels are in contact with raw water internally and condensation externally.

As can be seen in the other suction barrel line item, consistent with NUREG-1801 line item VII.C1-15, loss of material on the internal surfaces of the suction barrel is managed by the Service Water Integrity Program. The Service Water Integrity Program, in accordance with NRC GL 89-13, includes a condition monitoring program which inspects components such as pump barrels for erosion, corrosion, and blockage. Since the external environment of condensation is much milder than the internal environment of raw water, this program is equally as effective at managing loss of material on the external surfaces of the suction barrels as it is at managing loss of material on the internal surfaces of the barrels. However, the line item in question was compared with NUREG 1801 item VII.F1-1 (which recommends a plant-specific program) because NUREG 1801 Section VII.C1 does not address the external surfaces of stainless steel components containing raw water.

As stated in LRA Section B.1.26, the Service Water Integrity Program is consistent with the program described in NUREG-1801,Section XI.M20, "Open-Cycle Cooling Water System," with minor exceptions.

The 10 attributes of SRP-LR Appendix Al for the Service Water Integrity Program are the same as the 10 attributes of the program described in NUREG-1801,Section XI.M20 with the exceptions described in LRA Appendix B, Section B.1.26 111/14/200 375 ....PM .150

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Item Request Response 231 3.3.1-28-K-01 Page 3.3-102 has multiple line items for valve body managed using Instrument Air On page 3.3-102, the component type 'valve body' is managed using instrument air Quality. The response assumes this question refers to loss of material for both quality. Please clarify how the effectiveness of the IAQ program is to be verified, copper alloy and stainless steel valves exposed to treated air on internal surfaces.

As stated in LRA Section B.1.16, the Instrument Air Quality Program maintains humidity and particulates within acceptable limits, thereby preserving the environment of treated air that is not conducive to corrosion. Actions to verify the effectiveness of the program are not necessary. Corrosion in treated air systems only occurs as the result of the presence of impurities or moisture. Therefore, an effective instrument air quality program, which maintains impurities and moisture below specified limits, precludes the need for inspections. Operating experience at VYNPS has confirmed the effectiveness of the Instrument Air Quality Program in maintaining moisture and impurities within limits such that corrosion has not and will not affect the intended functions of these components.

In a previously approved staff position (NUREG-1 831, Donald C. Cook SER, Section 3.0.3.3.7), the staff concluded that an effective instrument air quality program, which maintains impurities and moisture below specified limits, is sufficient to demonstrate that the effects of aging will be adequately managed so that the intended functions will be maintained consistent with the current licensing basis for the period of extended operation.

In another precedent (Millstone SER, Section 3.3B.2.3.12 and NUREG-1 839, Point Beach SER, Section 3.2.2.3.1), on the basis of its review of current industry research and operating experience, the staff concluded that air on metal will not result in aging that will be of concern during the period of extended operation. The staff considers a dried air environment benign and that its contact with carbon steel, low-alloy steel, stainless steel, and cast stainless steel surfaces will not result in aging effects.

1:37:59 PM Page 79 of 150 1 1/14/2007 1:37.59 1111412007 PM Page 79 of 150

Item Request Response 232 3.3.1-30-K-01 LRA Amendment Beginning on page 3.3-61, the component types exposed to treated water are managed using water chemistry control - BWR. Please confirm that the VYNPS Water As stated in LRA Section B.1 .30.2, the Water Chemistry Control - BWR Program is Chemistry - BWR AMP is consistent with GALL XI.M32, "One-Time Inspection," as well consistent with the program described in NUREG-1801,Section XI.M2, "Water as with XI.M2, "Water Chemistry." Chemistry." The One-Time Inspection Program, described in LRA Section B.1 .21 includes inspections to verify the effectiveness of the water chemistry control aging management programs (Water Chemistry Control - Auxiliary Systems, Water Chemistry Control - BWR, and Water Chemistry Control - Closed Cooling Water) by confirming that unacceptable cracking, loss of material, and fouling is not occurring. As stated in LRA Section B.1 .21, the One-Time Inspection Program is a new program which will be consistent with the program described in NUREG-1801,Section XI.M32, "One-Time Inspection."

LRA Tables 3.1.1, 3.2.1, 3.3.1, and 3.4.1 indicate that the One-Time Inspection Program is credited along with the water chemistry control programs for line items for which GALL recommends a one-time inspection to confirm water chemistry control. For simplicity, the subsequent tables (Table 2's) do not list the One-Time Inspection Program each time a water chemistry control program is listed. However, since the One-Time Inspection Program is applicable to each water chemistry control program, it is also applicable to each line item that credits a water chemistry control program.

To provide further clarification, the effectiveness of the Water Chemistry Control -

Auxiliary Systems, BWR, and Closed Cooling Water programs is confirmed by the One-Time Inspection program. This requires an amendment to the license renewal application to change the Appendix A, SAR supplement descriptions for the Water Chemistry Control -Auxiliary Systems, BWR and Closed Cooling Water programs to explicitly state One-Time Inspection Program activities will confirm the effectiveness of these programs.

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Item Request ResDonse 233 3.3.1-31-K-01 LRA Amendment On page 3.2-50 in ESF and page 3.3-146 in auxiliary systems, component types exposed to treated water are managed using water chemistry control - BWR. Please As stated in LRA Section B.1.30.2, the Water Chemistry Control - BWR Program is confirm that the VYNPS Water Chemistry - BWR AMP isconsistent with GALL XI.M32, consistent with the program described in NUREG-1801,Section XI.M2, "Water "One-Time Inspection," as well as with XI.M2, "Water Chemistry."

Chemistry." The One-Time Inspection Program, described in LRA Section B.1.21 includes inspections to verify the effectiveness of the water chemistry control aging management programs (Water Chemistry Control - Auxiliary Systems, Water Chemistry Control - BWR, and Water Chemistry Control - Closed Cooling Water) by confirming that unacceptable cracking, loss of material, and fouling is not occurring. As stated in LRA Section B.1.21, the One-Time Inspection Program is a new program which will be consistent with the program described in NUREG-1 801,Section XI.M32, "One-Time Inspection."

LRA Tables 3.1.1, 3.2.1, 3.3.1, and 3.4.1 indicate that the One-Time Inspection Program is credited along with the water chemistry control programs for line items for which GALL recommends a one-time inspection to confirm water chemistry control. For simplicity, the subsequent tables (Table 2's) do not list the One-Time Inspection Program each time a water chemistry control program is listed. However, since the One-Time Inspection Program is applicable to each water chemistry control program, it is also applicable to each line item that credits a water chemistry control program.

To provide further clarification, the effectiveness of the Water Chemistry Control -

Auxiliary Systems, BWR, and Closed Cooling Water programs is confirmed by the One-Time Inspection program. This requires an amendment to the license renewal application to change the Appendix A, SAR supplement descriptions for the Water Chemistry Control -Auxiliary Systems, BWR and Closed Cooling Water programs to explicitly state One-Time Inspection Program activities will confirm the effectiveness of these programs.

234 3.3.1-51-K-01 Partial Duplicate of next question.

On page 3.3-132, the component type 'piping' is managed using water chemistry control - auxiliary systems. Please confirm that GALL v2 item VII.F1-8 is intended (not VIII.F1-8).

235 3.3.1-51-K-01 LRA Amendment On page 3.3-131, the component type 'humidifier housing' and on page 3.3-132, the component type 'piping' is managed using water chemistry control - auxiliary systems. That is correct. The NUREG-1801 Vol. 2 Item should be VII.F1-8 rather than VIII.F1-Please confirm that GALL v2 item VII.F1-8 is intended (not VIII.F1-8). 8 for these lines.

236 3.4.1-M-01 As stated in LRA Section B.1.28, the System Walkdown Program is consistent with In LRA Table 3.4.1, Item Number 3.4.1-22, the applicant states that their existing the program described in NUREG-1 801,Section XI.M36, "External Surfaces "System Walkdown Program",..."manages the loss of material for steel bolting through Monitoring." In accordance with this program description, surfaces that are the use of visual inspections...". How does the applicant intend to address the potential insulated are inspected when the external surface is exposed (i.e., maintenance) at loss of bolting material for subject bolting (normally flange bolting) that cannot be readily such intervals that would provide reasonable assurance that the effects of aging will seen - "visually inspected" - since most such bolting is usually covered by be managed such that applicable components will perform their intended function insulation/flashing material? during the period of extended operation.

Added Edit from 5/11/2006 email - Note: See generic question 2. EPRI aging assessment field 1007933 guide was reviewed by the staff.

- -', - .-.-- ~ -

Page 81 of 150

-~

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Item Request ResDonse 237 3.4.1 -M-02 LRCommitment 34 In reference to Question 3.4.1-1 above, it is the staff's present understanding that the LRA Amendment applicant currently intends to develop a "GALL-recom mended" bolting integrity program. If such a program is eventually developed, will it include inspections of plant A Bolting Integrity Program is under development that will address the aging condensate and feedwater system bolting; i.e., specifically flange bolting? management of bolting in the scope of license renewal including in scope flange bolting for the feedwater and condensate systems.

Bolting Integrity Program Descriptions are provided in LRA Amendments 16 and 23.

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Item Request Response 238 3.4.1 -M-03 LRA Table 3.4.1, Item Number 3.4.1-35 states that a Selective Leaching Program is The staff has recently discovered - during the April VYNPS AMP audit - that plant main not applicable because there are no copper alloy components subject to selective condenser tubing contains an admiralty brass-type of material which contains copper & leaching in the steam and power conversion systems. This statement was intended zinc. Such material - copper & zinc - has been known to leach out of condenser tubing to mean that there are no copper alloy components requiring an aging management via either by direct raw water erosion of the inside of the condenser tubes and/or by way ,review that are subject to selective leaching in the steam and power conversion of phenomena known as "de-zincification." Recent third-party chemistry control audits systems.

of V.YNPS have presented evidence that both copper and zinc ions are currently leaching out of the main condenser tubing and have been leaching out at a measurable A summary of the aging management review of the main condenser may be seen in rate for the last five (5) years. However; as noted in VYNPS LRA Table 3.4.1, Item LRA Table 3.4.2-1. As shown in this table and explained in plant-specific note 401, Number 3.4.1-35, the applicant stated that; "....there are no copper alloy components aging management of the main condenser is not based on analysis of materials, subject to selective leaching in the steam and power conversion systems...". What environments and aging effects. Condenser integrity required to perform the post-does the applicant intend to do to reduce and/or eliminate the apparent measurable and accident intended function (holdup and plate-out of MSIV leakage) is continuously continued leaching out of copper and zinc ions from the main condenser tubing? What confirmed by normal plant operation. This intended function does not require the does the applicant intend to do to eliminate and/or mitigate the introduction of these condenser to be leak-tight, and the post-accident conditions in the condenser will be ions (primarily the copper ions) into the reactor core areas of the plant? essentially atmospheric. Since normal plant operation assures adequate condenser pressure boundary integrity, the post-accident intended function to provide holdup Edit from 5/11/2006 email - The staff has recently discovered - during the April VYNPS volume and plate-out surface is assured. Previously approved staff positions AMP audit - that plant main condenser tubing contains an admiralty brass-type of (NUREG-1796, Dresden and Quad Cities SER, Section 3.4.2.4.4, and NUREG-material which contains copper & zinc. Such material - copper & zinc - has been 1769, Peach Bottom. SER, Section 3.4.2.3), concluded that main condenser integrity known to leach out of condenser tubing via either by direct raw water erosion of the is continually verified during normal plant operation and no aging management inside of the condenser tubes and/or by way of phenomena known as "de- program is required to assure the post-accident intended function.

zincification." Recent third-party chemistry control audits of VYNPS have presented evidence that both copper and zinc ions are currently leaching out of the main Therefore, loss of material due to leaching of copper and zinc ions from the main condenser tubing and have been leaching out at a measurable rate for the last five (5) condenser tubing is not an aging effect requiring management for the condenser years. However; as noted in VYNPS LRA Table 3.4.1, Item Number 3.4.1-35, the tubes.

applicant stated that; "....there are no copper alloy components subject to selective leaching in the steam and power conversion systems...". What does the applicant Leaching of copper and zinc ions from the main condenser tubing is also not a intend to do to reduce and/or eliminate the apparent measurable and continued license renewal issue related to aging of other components managed by the Water leaching out of copper and zinc ions from the main condenser tubing? What does the Chemistry Control - BWR Program and exposed to the copper and zinc ions from applicant intend to do to eliminate and/or mitigate the introduction of these ions the condenser. BWRVIP-130, BWR Vessel Internals Project BWR Water Chemistry (primarily the copper ions) into the reactor core areas of the plant? Guidelines - 2004 Revision, states that an assessment of risk to the fuel should be completed if feedwater copper values are above 0.1 ppb based on a quarterly average, or if zinc values are above 0.4 ppb based on a quarterly average. These recommendations are followed by VYNPS and there have been no fuel failures attributed solely to elevated feedwater copper or zinc in the last 20 years. Since the fuel is periodically replaced, it is not subject to aging management review.

Therefore, leaching of copper and zinc ions from the main condenser tubing is not a license renewal issue related to aging of fuel.

The leaching of zinc ions from the condenser has actually been beneficial in that it has helped to mitigate out-of-core dose rates. In fact, many BWRs are injecting zinc into the feedwater system to control out-of-core dose rates. VYNPS is planning to start zinc injection towards the end of 2006. Zinc also has a synergistic beneficial effect along with hydrogen water chemistry resulting in increased resistance of stainless steel and other alloys to intergranular stress corrosion cracking (IGSCC).

BWRVIP-1 30 also states that since soluble copper acts as a cathodic reactant like dissolved oxygen, copper can exacerbate corrosion phenomenon such as IGSCC.

However, VYNPS injects low levels of hydrogen in a Noble metal environment to mitigate IGSCC by keeping stainless steel electrochemical potential (ECP) values less than -230 mV relative to the standard hydrogen electrode. VYNPS has made significant efforts to reduce the amount of copper entering the reactor over the past Page 83 of 150 1:37:59 PM 11/14/2007 1:37:59 1111412007 PM Page 83 of 150

Item Request ResDonse 10 years. Where cycle average feedwater copper was once around 0.8 ppb, it is now near 0.3 ppb. Feedwater copper values for the first 4 months of 2006 were

<0.2 ppb.

Since VYNPS is maintaining ECP values in the desired range and has maintained feedwater copper levels as low as achievable, VYNPS is following BWRVIP guidance for feedwater copper. No other impacts of high copper and zinc levels were identified in BWRVIP-130. Plant procedures assure that VYNPS will continue to follow BWRVIP guidance for water chemistry. Therefore, further action is not necessary to address leaching of zinc and copper from condenser tubing for the period of extended operation.

VYNPS technical justification for continued operation of Entergy Northwest -

Vermont Yankee (ENVY) with feedwater copper >0.2 ppb revision #1 was reviewed by the staff.

239 3.4.2-M-01 LR Commitment 16 The staff has recently discovered, in the applicant's LRA, "Auxiliary Systems - LRA Amendment Miscellaneous Systems" Tables 3.3.2-13-02 and 3.3.2-13-13, that the applicant intends to use their existing Water Chemistry Control (BWR) Program to control loss of material LRA Table 3.3.1 indicates that the One-Time Inspection Program is credited along in their condensate and feedwater systems; i.e., loss of material in carbon steel piping with the water chemistry control programs for line items for which GALL subjected to steam temperatures >220 degrees F. For these systems, the GALL recommends a one-time inspection to confirm water chemistry control. For recommends the implementation of both a Water Chemistry Control AND a One-Time simplicity, the subsequent tables (Table 2's) do not list the One-Time Inspection Inspection Program to identify and mitigate loss of material in system piping. Does the Program each time a water chemistry control program is listed. However, since the applicant intend to implement a One-Time Inspection Program as well as their existing One-Time Inspection Program is applicable to each water chemistry control Water Chemistry Control Program to both identify and mitigate the loss of material in program, it is also applicable to each line item that credits a water chemistry control their condensate and feedwater systems? If yes, does the applicant intend to formally program.

produce a commitment to implement both programs? If the applicant does not intend to implement both a One-Time Inspection and Water Chemistry Control Program, why not? To provide further clarification, the effectiveness of the Water Chemistry Control -

Auxiliary Systems, BWR, and Closed Cooling Water programs is confirmed by the Edit from 5/11/2006 email - The staff has recently discovered, in the applicant's LRA, One-Time Inspection program. This requires an amendment to the license renewal "Auxiliary Systems - Miscellaneous Systems" Tables 3.3.2-13-02 and 3.3.2-13-13, that application to change the Appendix A, SAR supplement descriptions for the Water the applicant intends to use their existing Water Chemistry Control (BWR) Program to Chemistry Control -Auxiliary Systems, BWR and Closed Cooling Water programs to control loss of material in their condensate and feedwater systems; i.e., loss of material explicitly state One-Time Inspection Program activities will confirm the effectiveness in carbon steel piping subjected to steam temperatures >220 degrees F. For these of these programs.

systems, the GALL recommends the implementation of both a Water Chemistry Control AND a One-Time Inspection Program to identify and mitigate loss of material in system Also, license renewal commitment 16 has been issued to implement the One-Time piping. Does the applicant intend to implement a One-Time Inspection Program as well Inspection Program as described in LRA Section B.1.21. A commitment to as their existing Water Chemistry Control Program to both identify and mitigate the loss implement the Water Chemistry Control - BWR Program is not necessary as this is of material in their condensate and feedwater systems? If yes, does the applicant an existing program, which does not require enhancement.

intend to formally produce a commitment to implement both programs? If the applicant does not intend to implement both a One-Time Inspection and Water Chemistry Control Program, why not?

111/201:75 PM .................

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Item Reauest ResDonse 240 3.4.2-M-02 LR Commitment 16 The staff has recently discovered, in the applicant's LRA, Table 3.4.2-1; "Main LRA Amendment Condenser and MSIV Leakage Pathway - Heat Exchanger Tubes," that the applicant intends to use their existing Water Chemistry Control (BWR) Program to control any LRA Table 3.4.1 indicates that the One-Time Inspection Program is credited along loss of material in stainless steel (SS) condenser tubes; i.e., loss of material in SS with the water chemistry control programs for line items for which GALL piping (tubing) subjected to steam temperatures >270 degrees F. For these systems recommends a one-time inspection to confirm water chemistry control. For and any future modified systems, the GALL recommends implementation of both a simplicity, the subsequent tables (Table 2's) do not list the One-Time Inspection Water Chemistry Control AND a One-Time Inspection Program to identify and mitigate Program each time a water chemistry control program is listed. However, since the loss of material in system piping (tubing). Does the applicant intend to implement a One-Time Inspection Program is applicable to each water chemistry control One-Time Inspection Program as well as their existing Water Chemistry Control program, it is also applicable to each line item that credits a water chemistry control Program to both identify and mitigate loss of material from any future modified heat program.

exchanger tubing that could contain stainless steel that could be subjected to steam (or high temperature and high pressure water) temperatures >270 degrees F? If yes, does To provide further clarification, the effectiveness of the Water Chemistry Control -

the applicant intend to formally produce a commitment to implement both programs? If Auxiliary Systems, BWR, and Closed Cooling Water programs is confirmed by the the applicant does not intend to implement both a One-Time Inspection and Water One-Time Inspection program. This requires an amendment to the license renewal Chemistry Control Program for future, modified condensers, why not? application to change the Appendix A, SAR supplement descriptions for the Water Chemistry Control -Auxiliary Systems, BWR and Closed Cooling Water programs to Edit from 5/11/2006 Email - The staff has recently discovered, in the applicant's LRA, explicitly state One-Time Inspection Program activities will confirm the effectiveness Table 3.4.2-1; "Main Condenser and MSIV Leakage Pathway - Heat Exchanger Tubes," of these programs.

that the applicant intends to use their existing Water Chemistry Control (BWR) Program to control any loss of material in stainless steel (SS) condenser tubes; i.e., loss of Also, license renewal commitment 16 has been issued to implement the One-Time material in SS piping (tubing) subjected to steam temperatures >270 degrees F. For Inspection Program as described in LRA Section B.1.21. A commitment to these systems and any future modified systems, the GALL recommends implement the Water Chemistry Control - BWR Program is not necessary as this is implementation of both a Water Chemistry Control AND a One-Time Inspection an existing program, which does not require enhancement.

Program to identify and mitigate loss of material in system piping (tubing). Does the applicant intend to implement a One-Time Inspection Program as well as their existing Water Chemistry Control Program to both identify and mitigate loss of material from any future modified heat exchanger tubing that could contain stainless steel that could be subjected to steam (or high temperature and high pressure water) temperatures >270 degrees F? If yes, does the applicant intend to formally produce a commitment to implement both programs? If the applicant does not intend to implement both a One-Time Inspection and Water Chemistry Control Program for future, modified condensers, why not?

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Item Request ResDonse 241 3.4.2-M-03 LRA Table 3.3.2-13-9 does contain a line item for loss of material in copper alloy The staff has recently discovered, in the applicant's LRA, "Table3.3.2-13-9; "Circulating tubing subjected to raw water conditions. However, this line item does not represent Water System," that the applicant intends to use their existing Periodic Surveillance and the circulating water condenser tubing. Rather, it represents copper alloy instrument Periodic Maintenance (PSPM) Program to control loss of material in their circulating tubing in the circulating water system in cooling tower #2, cell 1 that requires aging water condenser tubing (interior); i.e., loss of material in copper alloy material (>15% management review due to potential spatial interaction.

zinc) subjected to raw water conditions. For this system, the GALL recommends the implementation of an Open-Cycle Cooling Water Control Program to identify and A summary of the aging management review of the main condenser may be seen in mitigate loss of material in system piping. Does the applicant intend to implement only LRA Table 3.4.2-1. As shown in this table and explained in plant-specific note 401, the PSPM Program to both identify and mitigate loss of material in the main condenser VYNPS does not intend to implement an aging management program for the main tubes rather than a "GALL-recommended" Open-Cycle Cooling Water Control condenser.

Program? If yes, does the applicant intend to formally produce a commitment to modify and implement the PSPM Program for control of material loss from the main condenser Aging management of the main condenser is not based on analysis of materials, tubing? If the applicant does not intend to implement both a PSPM and "GALL- environments and aging effects. Condenser integrity required to perform the post-recommended" Open-Cycle Cooling Water Control Program, why not? accident intended function (holdup and plate-out of MSIV leakage) is continuously confirmed by normal plant operation. This intended function does not require the Edit from 5/11/2006 email - The staff has recently discovered, in the applicant's LRA, condenser to be leak-tight, and the post-accident conditions in the condenser will be "Table 3.3.2-13-9; "Circulating Water System," that the applicant intends to use their essentially atmospheric. Since normal plant operation assures adequate condenser existing Periodic Surveillance and Periodic Maintenance (PSPM) Program to control pressure boundary integrity, the post-accident intended function to provide holdup loss of material in their circulating water condenser tubing (interior); i.e., loss of material volume and plate-out surface is assured. Previously approved staff positions in copper alloy material (>15% zinc) subjected to raw water conditions. For this system, (NUREG-1796, Dresden and Quad Cities SER, Section 3.4.2.4.4, and NUREG-the GALL recommends the implementation of an Open-Cycle Cooling Water Control 1769, Peach Bottom SER, Section 3.4.2.3), concluded that main condenser integrity Program to identify and mitigate loss of material in system piping. Does the applicant is continually verified during normal plant operation and no aging management intend to implement only the PSPM Program to both identify and mitigate loss of program is required to assure the post-accident intended function.

material in the main condenser tubes rather than a "GALL-recommended" Open-Cycle Cooling Water Control Program? If yes, does the applicant intend to formally produce a commitment to modify and implement the PSPM Program for control of material loss from the main condenser tubing? If the applicant does not intend to implement both a PSPM and "GALL-recommended" Open-Cycle Cooling Water Control Program, why not?

242 3.5.1-13-W-1 LRA Amendment In Table 3.5.2-1 on Page 3.5-50 of the LRA, for component Bellows (reactor vessel and drywell, one of the AMPs shown is CII-IWE, which is a plant-specific AMP. A Note C Table 3.5.2-1 on Page 3.5-50 of the LRA, for component Bellows (reactor vessel has been assigned to this AMR line item, component is different, but consistent with and drywell) is not consistent with the referenced NUREG-1801 Vol. 2 item. The material, environment, aging effect, and aging management program for NUREG-1801 Table 3.5.2-1 line item "Bellows (reactor vessel and drywell)" and the corresponding line item. AMP is consistent with NUREG-1 801 AMP description. Provide drawings line item in Table 2.4-1 should be deleted. The reactor vessel and drywell bellows showing how the LRA line item bellows are different from the GALL Table 1 Line Item perform no license renewal intended function. These components are not safety-3.5.1-13 bellows. Explain how the plant-specific VYNPS CII-IWE AMP is consistent related and are not required to demonstrate compliance with regulations identified in with the GALL specified AMP. 10 CFR 54.4(a)(3). Failure of the bellows will not prevent satisfactory accomplishment of a safety function. Leakage, if any, through the bellows is directed to a drain system that prevents the leakage from contacting the outer surface of the drywell shell.

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Item Request Response 243 3.5.1-16-W-1 LRA Amendment In Table 3.5.2-1 on page 3.5-54 of the LRA for component Drywell floor liner seal, the AMP shown is Structures Monitoring. The applicant is asked to verify that the ClI-IWE The aging management activity will be the same whether included under the AMP will not be used instead to manage the aging of the moisture barrier. umbrella of the Structures Monitoring Program or under the umbrella of the CII-IWE Program, For clarification, the CII-IWE Program will manage the effects of aging on the moisture barrier through the period of extended operation. Note E remains the correct note since the CII-IWE Program is plant specific. The LRA will be amended as follows:

Table 3.5.2-1 willbe updated to reflect the AMP as CII-IWE Table line Item 3.5.1-16 will be updated to read:

"The aging effects cited in the NUREG-1 801 item are loss of sealing and leakage.

Loss of sealing is a consequence of the aging effects cracking and change in material properties.

For VYNPS, the Containment Leak Rate Program manages cracking and change in material properties for the primary containment seal and gaskets. The Inservice Inspection -IWE manages cracking and change in material properties for the primary containment moisture barrier."

Also see Response #76 244 3.5.1-44-W-1 LRA Amendment In Table 3.5.2-6 on Page 3.5-80 of the LRA, for component seals and gaskets (doors, manways and hatches), material rubber in a protected from weather environment; the Table 3.5.2-6 on Page 3.5-80 of the LRA, for component seals and gaskets (doors, aging effects are cracking and change in material properties. One of the aging manways and hatches), material rubber in a protected from weather environment; management programs shown is Structures Monitoring. The GALL line item referenced the aging effects are cracking and change in material properties. The LRA will be is III.A6-12 and the Table 1 reference is 3.5.1-44. The note shown is E, different AMP clarified to indicate that Note "A" applies to the line for SMP.

than shown in GALL. However, GALL Line Item III.A6-12 and Table 1 Line Item 3.5.1-44 both specify the Structures Monitoring Program. Explain why the note shown is not A instead of E for the lower half of this AMR line item.

245 3.5.1-45-W-1 RAI 3.6.2.2.N-08 In Table 3.5.2-5 on Page 3.5-67 of the LRA, for component Vernon Dam external walls above/below grade, material concrete in an exposed to fluid environment; the AMP The Vernon Dam FERC Inspection Program was described as a plant-specific shown is Vernon Dam FERC Inspection. The referenced GALL line item for all three program in Appendix B of the application because there is no program description in environments is III.A6-7. GALL Line Item II1.A6-7 states the following under AMP: NUREG-1801. As a plant-specific program, we selected Note E. Note A would be Chapter XI.S7, "Regulatory Guide 1.127, Inspection of Water-Control Structures an acceptable alternative.

Associated with Nuclear Power Plants" or the FERC/US Army Corp of Engineers dam inspections and maintenance programs. Since one of the AMPs under this GALL line item is FERC dam inspections, explain why the note assigned to the LRA AMR line item is E instead of A; consistent with GALL.

246 3.5.1-47-W-1 RAI 3.6.2.2.N-08 In Table 3.5.2-5 on Page 3.5-66 of the LRA, for component Vemon Dam structural steel, material carbon steel in an exposed to weather, protected from weather, and The Vernon Dam FERC Inspection Program was described as a plant-specific exposed to fluid environment; the AMP shown is Vernon Dam FERC Inspection. The program in Appendix B of the application because there is no program description in referenced GALL line item for all three environments is Ill.A6-1 1. GALL Line Item III.A6- NUREG-1801. As a plant-specific program, we selected Note E. Note A would be 11 states the following under AMP: Chapter XI.S7, "Regulatory Guide 1.127, Inspection an acceptable alternative.

of Water-Control Structures Associated with Nuclear Power Plants" or the FERC/US Army Corp of Engineers dam inspections and maintenance programs. Since one of the AMPs under this GALL line item is FERC dam inspections, explain why the note assigned to the three LRA AMR line items is E instead of A; consistent with GALL.

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Item Reauest ResDonse 247 3.5.1-58-W-1 NUREG-1801 does not mention every type of component that may be subject to In Table 3.5.2-6 on Page 3.5-71 of the LRA, for component conduit, material galvanized aging management review (e.g., conduit is not in NUREG-1801) nor does the steel in a protected weather environment; the aging effect is none. The GALL line item terminology used at a specific plant always align with that used in GALL.

referenced is 111.12-5, which is for the following components: Support members; welds; Consequently, matching plant components to NUREG-1801 components is bolted connections; support anchorage to building structure. Explain why the LRA AMR occasionally subjective. In this particular case, conduit, which has no specific line item has a Note A shown instead of a Note C, different component with respect to function other than to support and protect cable, was considered a support member the GALL line item. Or as an alternative, a letter Note A with a number note explaining and Note A was applied. The use of either Note A or C has no real impact on the that the component is different. aging management review results.

248 3.5.1-58-W-2 LRA Amendment In Table 3.5.2-6 on Page 3.5-72 of the LRA, for component electrical and instrument panels and enclosures, material galvanized steel in a protected from weather NUREG-1 801 does not mention every type of component that may be subject to environment; the aging effect is none. The GALL line item referenced is 111.B3-3, which aging management review (e.g., panel is not in NUREG-1801) nor does the is for the following components: Support members; welds; bolted connections; support terminology used at a specific plant always align with that used in GALL.

anchorage to building structure. Explain why the LRA AMR line item has a Note A Consequently, matching plant components to NUREG-1 801 components is shown instead of a Note C, different component with respect to the GALL line item. Or occasionally subjective. In this particular case, panels, which have no specific as an alternative, a letter Note Awith a number note explaining that the component is function other than to support and protect electrical equipment, was considered a different. support member and Note A was applied. The use of either Note A or C has no real impact on the aging management review results.

Note "A"will be changed to Note "C"for component electrical and instrument panels and enclosures, material galvanized steel in a protected from weather environment in Table 3.5.2-6 on Page 3.5-72 of the LRA. No change is required to the other entries for this line item.

249 3.5.1-58-W-3 LRA Amendment In Table 3.5.2-6 on Page 3.5-73 of the LRA, for component flood curb, material galvanized steel in a protected from weather environment; the aging effect is none. The Unlike the conduits and panels compared to supports in questions 3.5.1-58-W-1 and GALL line item referenced is 111.B5-3, which is for the following components: Support W-2, the component flood curb should not have been considered a match. Note C members; welds; bolted connections; support anchorage to building structure. Explain should be applied here; although the use of either Note A or C has no real impact on why the LRA AMR line item has a Note A shown instead of a Note C, different the aging management review results.

component with respect to the GALL line item. Or as an alternative, a letter Note A with a number note explaining that the component is different. Note "A" will be changed to Note "C" for component flood curb, material galvanized steel in a protected from weather environment in Table 3.5.2-6 on Page 3.5-73 of the LRA. No change is required to the other entries for this line item.

250 3.5.1-8-W-1 LRA Amendment In Table 3.5.2-1 on Page 3.5-53 of the LRA for component Torus shell with the aging effect cracking-fatigue, the note assigned is E. Note E is consistent with NUREG-1801 Note A should be applied here. The LRA will be amended to indicate Note A.

material, environment, and aging effect but a different aging management program is credited. Explain why this note is E when the AMP shown for this line item is TLAA and the referenced GALL Line Item 11.B1.1-4 also specifies a TLAA.

251 3.5.2-2-W-1 As shown in Table 3.5.2-2, the aging effect for component spent fuel pool storage In Table 3.5.2-2 on Page 3.5-57 of the LRA, for component Spent fuel pool storage racks is loss of material. The specific aging mechanism is pitting and crevice racks, material stainless steel in an exposed to fluid environment; the aging effect is corrosion because stainless steels are susceptible to this aging mechanism when loss of material. Explain by what aging mechanism loss of material occurs and why the exposed to oxygenated water in a treated water environment. Cracking is not an aging effect is not cracking. aging effect requiring management for stainless steel in the spent fuel pool because cracking due to stress corrosion is dependent on temperature (>140'F). The spent fuel pool treated water environment is less than 1400F.

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11 4120071:37.59PM! Page 88 of 150

Item Request ResDonse 252 3.5.2-4-W-1 As identified in the response to question A-W-1 3, loss of material due to pitting and In Table 3.5.2-4 on Page 3.5-61 of the LRA, for component Blowout or blow-off panels, crevice corrosion of aluminum components in an outdoor environment is not material aluminum in an exposed to weather environment; the aging effect is none. applicable if the atmospheric environment is non-aggressive. Plant-specific Note Reference question A-W-1 3 and explain how this component is protected from constant 503 provides the basis for concluding the environment is non-aggressive. In this wetting and drying conditions. non-aggressive environment, the occasional wetting and drying from normal outdoor weather does not result in significant loss of material in aluminum components, hence, there are no aging effects requiring management.

253 3.5.2-4-W-2 As identified in Table 3.5.2-4 on Page 3.5-61 of the LRA, for steel piles, material In Table 3.5.2-4 on Page 3.5-61 of the LRA, for component Steel Piles, material carbon carbon steel in an exposed to weather environment; the aging effect is none.

steel in an exposed to weather environment; the aging effect is none. Note 504 Although a soil environment is not identified, the listed environment, exposed to discusses steel piles driven into soils (a soil environment, not a weather environment) weather, is intended to include both an above grade environment and a below grade with no significant effects due to corrosion. Explain how the soil environment relates to environment as described in Table 3.0-2 of the application. The below grade the weather environment to justify no aging effect. environment applies to the steel piles. As such the statement made in Note 504 is applicable.

254 3.5.2-5-W-1 As identified in the response to question A-W-13, loss of material due to pitting and In Table 3.5.2-5 on Page 3.5-65 of the LRA, for component N2 tank steel supports, crevice corrosion of stainless steel components in an outdoor environment is not material stainless steel in an exposed to weather environment; the aging effect is none. applicable if the atmospheric environment is non-aggressive. Plant-specific Note Reference question A-W-1 3 and explain how this component is protected from constant 503 provides the basis for concluding the environment is non-aggressive. In this wetting and drying conditions. non-aggressive environment, the occasional wetting and drying from normal outdoor weather does not result in significant loss of material in stainless steel components, hence, there are no aging effects requiring management.

255 3.5.2-5-W-2 LRA Amendment In Table 3.5.2-5 on Page 3.5-65 of the LRA, for component Transmission towers, material galvanized steel in an exposed to weather environment; the aging effect is As identified in the response to question A-W-13, loss of material is the aging effect none. Reference question A-W-1 3 and explain how this component is protected from requiring management and the Structures Monitoring Program is the aging constant wetting and drying conditions. management program. This is-consistent NUREG-1801 Vol. 2 Item I11.B4-7, summarized in Table 1 Item 3.5.1-50, and Note C applies.

256 3.5.2-5-W-3 RAI 3.6.2.2.N-08 In Table 3.5.2-5 on Page 3.5-67 of the LRA, for component Vernon Dam external walls, floor slabs and interior walls, material concrete in a protected from weather Since quality of concrete used at Vernon Dam has not been confirmed, it would environment; the aging effect shown is none with the AMP shown as Vernon Dam have been more appropriate to show for the associated aging effectsfor the line FERC Inspection. VYNPS discusses throughout its LRA Section 3.5 further evaluations items in question. However, the same aging management activity, the FERC that VYNPS concrete does not have aging effects because the quality of the concrete inspection, is still appropriate to manage aging effects associated with the Vernon used during construction was to the standards of ACI-318 and ACI 201.2R. Vernon Dam concrete components.

Dam is a very old structure and was not built by the owners of VYNPS. Provide documentation and justification that the quality of the concrete used at Vernon Dam is also to the standards of ACI-318 and AC! 201 .R such that the AMR statement None for aging effects of the Dam concrete is justified.

257 3.5.2-6-W-1 LRA Amendment In Table 3.5.2-6 on Page 3.5-71 of the LRA, for component conduit, material galvanized steel in an exposed to weather environment; the aging effect is none. Reference As identified in the response to question A-W-13, loss of material is the aging effect question A-W-1 3 and explain how this component is protected from constant wetting requiring management and the Structures Monitoring Program is the aging and drying conditions. management program. This is consistent NUREG-1801 Vol. 2 Item II1.B4-7, summarized in Table 1 Item 3.5.1-50, and Note C applies.

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Item Request ResDonse 258 3.5.2-6-W-2 LRA Amendment In Table 3.5.2-6 on Page 3.5-71 of the LRA, for component conduit support, material galvanized steel in an exposed to weather environment; the aging effect is none. As identified in the response to question A-W-13, loss of material is the aging effect Reference question A-W-13 and explain how this component is protected from constant requiring management and the Structures Monitoring Program is the aging wetting and drying conditions. management program. This is consistent NUREG-1801 Vol. 2 Item III.B4-7, summarized in Table 1 Item 3.5.1-50, and Note C applies.

259 3.5.2-6-W-3 LRA Amendment In Table 3.5.2-6 on Page 3.5-72 of the LRA, for component electrical and instrument panels and enclosures, material galvanized steel in an exposed to weather As identified in the response to question A-W-13, loss of material is the aging effect environment; the aging effect is none. Reference question A-W-13 and explain how requiring management and the Structures Monitoring Program is the aging this component is protected from constant wetting and drying conditions. management program. This is consistent NUREG-1801 Vol. 2 Item III.B4-7, summarized in Table 1 Item 3.5.1-50, and Note C applies.

260 3.5.2-6-W-4 As identified in the response to question A-W-13, loss of material due to pitting and In Table 3.5.2-6 on Page 3.5-75 of the LRA, for component Vents and louvers, material crevice corrosion of aluminum components in an outdoor environment is not aluminum in an exposed to weather environment; the aging effect is none. Reference applicable if the atmospheric environment is non-aggressive. Plant-specific Note question A-W-13 and explain how this component is protected from constant wetting 503 provides the basis for concluding the environment is non-aggressive. In this and drying conditions. non-aggressive environment, the occasional wetting and drying from normal outdoor weather does not result in significant loss of material in aluminum components, hence, there are no aging effects requiring management.

261 3.5.2-6-W-5 As identified in the response to question A-W-13, loss of material due to pitting and In Table 3.5.2-6 on Page 3.5-76 of the LRA,.for component Anchor bolts, material crevice corrosion of stainless steel components in an outdoor environment is not stainless steel in an exposed to weather environment; the aging effect is none. applicable if the atmospheric environment is non-aggressive. Plant-specific Note Reference question A-W-13 and explain how this component is protected from constant 503 provides the basis for concluding the environment is non-aggressive. In this wetting and drying conditions. non-aggressive environment, the occasional wetting and drying from normal outdoor weather does not result in significant loss of material in stainless steel components, hence, there are no aging effects requiring management.

262 3.5.2-6-W-6 As identified in the response to question A-W-13, loss of material due to pitting and In Table 3.5.2-6 on Page 3.5-78 of the LRA, for component structural bolting, material crevice corrosion of stainless steel components in an outdoor environment is not stainless steel in an exposed to weather environment; the aging effect is none. applicable ifthe atmospheric environment is non-aggressive. Plant-specific Note Reference question A-W-1 3 and explain how this component is protected from constant 503 provides the basis for concluding the environment is non-aggressive. In this wetting and drying conditions. non-aggressive environment, the occasional wetting and drying from normal outdoor weather does not result in significant loss of material in stainless steel components, hence, there are no aging effects requiring management.

263 3.5.2-6-W-7 LRA Amendment In Table 3.5.2-6 on Page 3.5-78 of the LRA, for component structural bolting, material galvanized steel in an exposed to weather environment; the aging effect is none. As identified in the response to question A-W-13, loss of material is the aging effect Reference question A-W-13 and explain how this component is protected from constant requiring management and the Structures Monitoring Program is the aging wetting and drying conditions. management program. This is consistent NUREG-1801 Vol. 2 Item III.B4-7, summarized in Table 1 Item 3.5.1-50, and Note C applies.

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Item Request Response 264 3.5.2-6-W-8 The PVC water stops identified in Table 3.5.2-6 on Page 3.5-80 of the LRA are used In Table 3.5.2-6 on Page 3.5-80 of the LRA, for component water stops, material PVC in the cooling tower reinforced concrete basin and are not exposed to the same in a protected from weather environment; the aging effect is none. By definition the environment as the cooling tower fill material. Therefore the aging effects are not the component stops water, so it could be exposed to water. In LRA Table 3.5.2-4 on Page same. The aging effects attributed to PVC water stops are evaluated based upon 3.5-64 for component Cooling tower fill, material PVC, environment exposed to fluid Section 7.0 of the Structural Tools. Exposure to water for these commodities is environment, the aging effects listed are cracking and change in material properties. insignificant, since the concrete encapsulating the PVC water stop and the Provide a technical basis why PVC water stops do not have any aging effects which protection provided by the surrounding concrete, provides ample protection such need aging management when they could be exposed to a fluid environment also. that aging management is not required. USFAR Fig 12.2-33 (G-200357) "Cooling Provide the specification that called for PVC water stops during construction instead of Tower No. 2 Basin Plan View" identifies the use of PVC water stops at VYNPS.

rubber.

265 3.5.2-6-W-9 Pyrocrete (used for fire proofing) is cement base composite material. Pyrocrete is In Table 3.5.2-6 on Page 3.5-78 of the LRA, for component Fire proofing, material not identified in NUREG-1801. As such, our technical evaluation of pyrocrete in Pyrocrete in a protected from weather environment; the aging effect is none. Provide a determining applicable aging effects was the same as that for concrete which is technical basis why Pyrocrete does not have any aging effects in the environment listed. based on EPRI 1002950, Aging Effects for Structures And Structural Components (Structural Tools), Revision 1, Section 5. Accordingly, no aging effects were determined for pyrocrete protected from weather. However, as indicated In Table 3.5.2-6 on Page 3.5-78 of the LRA, the Fire Protection Program and Structures Monitoring Program will confirm the absence of significant aging effects throughout the period of extended operation.

266 A-W-01 LRA Amendment LRA Table 3.5.1, Item Number 3.5.1-5, has the following statement under the discussion column: The drywell steel where the drywell shell is embedded is inspected For LRA Table 3.5.1, Item 3.5.1-5, the discussion column should read, "The drywell in accordance with the Containment Inservice Inspection (IWE) Program and Structures steel shell and the moisture barrier where the drywell shell becomes embedded in Monitoring Program. This is an impossible inspection. Change this discussion the drywell concrete floor are inspected in accordance with the Containment statement to agree with LRA Section 3.5.2.2.1.4 that states: The drywell steel shell and Inservice Inspection (IWE) Program. To be consistent, LRA Section 3.5.2.2.1.4, the moisture barrier where the drywell shell becomes embedded in the drywell concrete should indicate that the drywell to floor moisture barrier will be inspected under the floor are inspected in accordance with the Containment Inservice Inspection (IWE) Containment Inservice Inspection (IWE) Program. The inspection is part of the Program and Structures Monitoring Program. Containment Inservice Inspection (IWE) Program and will be retained as part of that program through the period of extended operation. The LRA will be amended as stated by formal correspondence.

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Item Request Response 267 A-W-02 LRA Amendment LRA Table 3.5.1, Item Number 3.5.1-9, has the following statement under the discussion column: Not applicable. See Section 3.5.2.2.1.6. However, the following The LRA will be amended to reflect the following changes. Fatigue analyses have statement is made in LRA Section 3.5.2.2.1.6: "Fatigue TLAAs for the steel drywell, been evaluated for the torus, drywell to torus vent system, and torus penetrations.

torus, and associated penetrations are evaluated and documented in Section 4.6." The The following line for the torus penetrations will be added to Table 3.5.2-1:

components associated with LRA Table 3.5.1, Item Number 3.5.1-9 are: penetration sleeves, penetration bellows; suppression pool shell, unbraced downcomers. Explain Torus mechanical penetrations PB, SSR how Item number 3.5.1-9 is not applicable when a fatigue TLAA has been performed for Carbon steelDProtected from weather Cracking the torus and penetrations. Explain why the vent line, vent header and vent line bellows (fatigue) TLAA-metal fatigue[ ll.B4-4 are not listed in LRA Sections 3.5.2.2.1.6 and 4.6 as referenced in Table 3.5.1, Line (C-13) 3.5.1 9A Item 3.5.1-8.

The evaluation of the drywell to torus vent system fatigue analysis determined that it was not a TLAA. The significant contributor to fatigue of the vent system is post-LOCA chugging, a once in plant-life event. As there will still be only one design basis LOCA for the life of the plant, including the period of extended operation, this analysis is not based on a time-limited assumption and is not a TLAA. Since fatigue for the vent system is event driven and is not an age related effect, the following line will be deleted from Table 3.5.2-1 :

Drywell to torus vent system PB, SSR Carbon steel Protected from weather Cracking (fatigue) TLAA-metal fatigueDll.B1.1-4 (C-21) 3.5.1 8A The discussion column entry for Table 3.5.1 item 3.5.1-8 will be changed to state:

Fatigue analysis is a TLAA for the torus shell. Fatigue of the torus to drywell vent system is event driven and the analysis is not a TLAA. See Section 3.5.2.2.1.6.

The discussion column entry for Table 3.5.1 item 3.5.1-9 will be changed to state:

Fatigue analysis is a TLAA for the torus penetrations. See Section 3.5.2.2.1.6.

Section 3.5.2.2.1.6 will be changed to read as follows:

TLAA are evaluated in accordance with 10 CFR 54.21 (c) as documented in Section

4. Fatigue TLAAs for the torus and associated penetrations are evaluated and documented in Section 4.6.

Section 3.5.2.3, Time-Limited Aging Analyses, will be changed to state:

TLAA identified for structural components and commodities include fatigue analyses for the torus and torus penetrations. These topics are discussed in Section 4.6.

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Item Request Response 268 A-W-03 LRA Amendment LRA Table 3.5.1, Item Number 3.5.1-12, under the discussion column, does not make reference to LRA Section 3.5.2.2.1.8 for further evaluation. Explain why this link is not A link from items 3.5.1-12 and 3.5.1-13 will be added to section 3.5.2.2.1.8.

made to the further evaluation section. Explain the need for augmented ultrasonic exams to detect fine cracks since a CLB fatigue analysis does exist. Section 3.5.2.2.1.8 should state:

Cyclic loading can lead to cracking of steel and stainless steel penetration bellows, and dissimilar metal welds of BWR containments and BWR suppression pool shell and downcomers.

Cracking due to cyclic loading is not expected to occur in the drywell, torus and associated penetration bellows, penetration sleeves, unbraced downcomers, and dissimilar metal welds. A review of plant operating experience did not identify cracking of the components, and primary containment leakage has not been identified as a concern. Nonetheless the existing Containment Leak Rate Program with augmented ultra sonic exams and Containment Inservice Inspection - IWE, will continue to be used to detect cracking. Observed conditions that have the potential for impacting an intended function are evaluated or corrected in accordance with the corrective action process. The Containment Inservice Inspection - IWE and Containment Leak Rate programs are described in Appendix B.

269 A-W-04 LRA Amendment LRA Table 3.5.1, Item Number 3.5.1-13, under the discussion column, does not make reference to LRA Section 3.5.2.2.1.8 for further evaluation. Explain why this link is not See response to Item 268.

made to the further evaluation section. Explain the need for augmented ultrasonic exams to detect fine cracks since a CLB fatigue analysis does exist.

270 A-W-05 LRA Amendment LRA Table 3.5.1, Item Number 3.5.1-16, under the discussion column, states that seals and gaskets are not included in the Containment Inservice Inspection Program at VYNPS uses a moisture barrier to seal the joint between the containment drywell VYNPS. One of the components for this item number is moisture barriers. Explain how shell and drywell concrete floor. Moisture barrier is listed in LRA table 3.5.2-1 as VYNPS seals the joint between the containment drywell shell and drywell concrete floor drywell floor liner seal. Aging effects on the drywell moisture barrier will be if there is no moisture barrier. Explain why the inspection of this joint is not part of the managed under the CII-IWE program (also see audit question 3.5.1-16-W-1 above).

Containment Inservice Inspection Program at VYNPS.

For clarity, drywell floor liner seal will be changed to drywell shell to floor seal (moisture barrier). (Also see audit questions #76 and 243 which address changes to the LRA )

271 A-W-06 It may be a misnomer to refer to these components as active components since LRA Table 3.5.1, Item Number 3.5.1-17, under the discussion column, states that locks, 10CFR54.21 (a)(1)(i) does not refer to active or passive components, but rather hinges, and closure mechanisms are active components and are therefore not subject excludes components from aging management review that perform an intended to an aging management review. Provide any license renewal regulatory guidance function, as described in § 54.4, with moving parts or with a change in configuration document or previous LRA NRC SER that has ever stated that locks, hinges, and or properties. Locks, hinges, and closure mechanisms perform their functions with closure mechanisms are active components. If locks, hinges, and closure mechanisms moving parts.

are active components at VYNPS, provide an itemized list of these active components This exception is not based on a qualified life or specified time period of with their qualified life or specified time period of replacement. Explain how VYNPS replacement for a component. 10CFR54.21(a)(1)(ii) provides a separate exclusion tracks the active life of these components before replacement. for components that are replaced based on a qualified life.

Other precedents for locks, hinges, and closure mechanisms as active components that have received approval by the NRC are found in Peach Bottom(NUREG 1769, Section 3.0.3.14.2 Pg 3-58) and Millstone (NUREG 1838, Section 3.3A.2.1.4 Pg 3-245)

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Item Request ResDonse ResDonse 272 A-W-07 Condition reports are a primary source of operating experience documentation LRA Table 3.5.1, Item Number 3.5.1-21, under the discussion column, states that reviewed for license renewal. Condition reports document negative inspection VYNPS plant operating experience has not identified fretting or lock up due to results. NUREG-1801 defines neither fretting nor lockup and further confuses the mechanical wear for the drywell head and downcomers. Plant operating experience subject by stating that fretting and lockup are caused by mechanical wear which is does not find fretting or lock up due to mechanical wear, inspections do. Explain if an aging mechanism resulting in the aging effect loss of material. The definition in VYNPS does not currently inspect for wear of the drywell head and downcomer pipes NUREG-1801, Section IXE, merely states that fretting and lockup is an aging effect under the CLB using the Containment Inservice Inspection Program. If VYNPS does along with a cause, but doesn't say what it is or what it looks like. As indicated in the currently inspect these components for wear, justify not performing these same line item for drywell head in Table 3.5.2-1, the Containment Inservice Inspection-inspections during an extended license period. If required, provide drawings showing IWE Program and the Containment Leak Rate Program manage loss of material.

the spacial distance between components such that fretting cannot occur. Loss of material is the aging effect caused by mechanical wear. VYNPS inspects the drywell head and downcomers (Torus vent system) per the requirements of ASME Section XI.

In addition, the drywell head is a stationary or fixed component and the downcomers are stationary, well-braced components and the spatial distance between connecting components makes it unlikely for fretting and lockup to occur.

273 A-W-08 The NUREG-1 801 referenced programs involve visual inspections and leak testing LRA Table 3.5.1, Item Number 3.5.1-11, under the discussion column, states that which are not optimum methods for managing SCC. Therefore, when possible, it is cracking due to stress corrosion cracking for stainless steel vent line bellows is not more appropriate to assess the conditions and identify whether the applicable aging applicable. Explain if the VYNPS Containment Inservice Inspection Program and effects require management. As stated in Section 3.5.2.2.1.7, stress corrosion Containment Leak Rate Program are used currently to detect cracking of stainless steel cracking is not an aging effect requiring management for the penetration sleeves vent line bellows by inspection and testing. Explain why it is not more appropriate to and bellows, since the conditions necessary for SCC do not exist.

take credit for these two programs to detect cracking without the need for additional enhanced examinations then to say not applicable. However these components are evaluated for other aging effects requiring management, such as cracking, as shown in Table 3.5.2-1.

274 A-W-09 VYNPS inaccessible and accessible concrete areas are designed in accordance LRA Table 3.5.1, Item Number 3.5.1-26, under the discussion column, states that with American Concrete Institute (ACI) specification ACI 318-63, Building Code freeze-thaw is not an applicable aging mechanism for these groups of structures at Requirements for Reinforced Concrete. VYNPS concrete also meets requirements VYNPS. Provide documentation showing the weathering conditions (weathering index) of later ACI guide ACI 201.2R-77, Guide to Durable Concrete, since both documents for VYNPS and the specification requiring concrete to have an air content of 3% to 6% use the same American Society for Testing and Material (ASTM) standards for and water to cement ratio of 0.35 to 0.45. selection, application and testing of concrete.

VYNPS concrete was provided with air content between 3% and 5% and a water/cement ration between 0.44 and 0.60 (Ref. VYNPS site specification EBASCO 15-65, Sections 7.0 and 12.5). VYNPS is located at severe weathering region (weathering index >100 day-inch/yr) as indicated in ASTM C33, FIG. 1.

Although the water/cement ratio falls outside the listed range of 0.35 to 0.45, given all parameters associated with concrete mix design VYNPS concrete meets the quality requirements of ACI to ensure acceptable concrete is obtained. Nonetheless concrete will be managed under the aging management programs identified in the 3.5.2 tables.

275 A-W-10 For construction of concrete, VYNPS site Specification EBASCO 15-65, Concrete For LRA Table 3.5.1, Item Number 3.5.1-27, provide documentation showing that Large Work, identifies the same ASTM standards for achieving durable concrete as inaccessible areas concrete was constructed in accordance with the recommendations those identified in ACI 201.2R77, "Guide to durable concrete."

in ACI 201.2R-77.

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Item Request Response 276 A-W-11 The VYNPS concrete is expected to experience average general area For LRA Table 3.5.1, Item Number 3.5.1-33, provide the maximum temperatures that temperature of 150°F and local area maximum temperature less than 200°F. The concrete experiences in Group Athrough 5 structures. d"ell cooling system recirculates the drywell atmosphere through heat exchangers to maintain ambient temperature in the drywell between 135 and 165°F (average 150°F). (Ref VYNPS UFSAR 5.2.3.2 and 10.12.3) The concrete temperature around piping penetrations for high temperature lines, such as the steam lines and other reactor system lines is protected by piping insulation and air gaps. (Ref UFSAR 5.2.3.4.2).

277 A-W-12 [Original Response]

[Follow-up Question] LRA Table 3.5.1 relates only to structures and structural supports. Thus, the The applicant is asked to verify that there are no non-metallic (rubber) vibration isolation statement that no vibration isolation elements are in scope and subject to aging elements used to structurally support the emergency diesel generator, HVAC system management review applies only to structural vibration isolation elements. Vibration equipment, and miscellaneous mechanical equipment and that all vibration isolation to isolation elements for mechanical system components are subject to aging systems attached to these components is by expansion joints and flexible connections. management review. For example, LRA Table 3.3.2-4 contains expansion joint in

[Original Question] the emergency diesel generator system and LRA Table 3.3.2-10 contains duct LRA Table 3.5.1, Item Number 3.5.1-41, under the discussion column, states that no flexible connections and expansion joints in heating, ventilation, and air conditioning vibration isolation elements at VYNPS are in scope and subject to aging management systems.

review. Explain the lack of vibration isolation elements for HVAC system components, (New Response) the emergency diesel generator and miscellaneous mechanical equipment. As stated in Table 3.5.1 Line Item 3.5.1-41, there are no non-metallic (rubber) vibration isolation elements used to structurally support the EDG, HVAC system equipment, and miscellaneous mechanical equipment that is within the scope of license renewal. Vibration isolation to systems attached to these components is by expansion joints and flexible connections.

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Item Request Response 278 A-W-13 LRA Amendment LRA Table 3.5.1, Item Number 3.5.1-50, under the discussion column, states that loss of material due to pitting and crevice corrosion of groups B2 and B4 galvanized steel, Loss of material due to pitting and crevice corrosion of aluminum and stainless steel aluminum, and stainless steel components in an outdoor air environment is not components in an outdoor environment is not applicable if the atmospheric applicable at VYNPS. NUREG-1833 on Page 93 for Item TP-6 states anapproved environment is non-aggressive. The ambient environment at VYNPS is not precedent exists for adding this material, environment, aging effect, and program chemically polluted by vapors of sulfur dioxide or other similar substances and the combination to the GALL Report. As shown in RNP SER Section 3.5.2.4.3.2, external environment does not contain saltwater or high chloride content. In this non-galvanized steel and stainless steel in an outdoor air environment could result in loss of aggressive environment, the occasional wetting and drying from normal outdoor material due to constant wetting and drying conditions. Aluminum would also be weather does not result in any significant loss of material in, aluminum or stainless susceptible to a similar kind of aging effect in the outdoor environment. Provide a steel components. The conclusion that no aging effects require management for discussion of the actual group B2 and 84 galvanized steel, aluminum, and stainless these materials in an outdoor air environment is supported by operating experience steel VYNPS components which are within the scope of license renewal and exposed to and by previously approved staff positions documented in the Farley SER (NUREG-an outdoor air environment. Discuss the location of these components at VYNPS and 1825, page 3-314).

how they are protected from constant wetting and drying conditions.

Components that may be considered in the B2 and B4 grouping consists of those line items in Table 3.5.2-6 including the plant specific Note 503. Note 503 provides the basis for concluding the environment is non-aggressive and the conclusion that there are no aging effects requiring management.

The aging management review results for galvanized steel components in outdoor air should indicate loss of material as an aging effect with structures monitoring as the aging management program. The following discussion applies to the discussion column entry for item 3.5.1-50.

Consistent with NUREG-1 801 for galvanized steel components in outdoor air. The Structures Monitoring Program will manage loss of material.

Loss of material is not an applicable aging effect for stainless steel or aluminum components in outdoor air. The ambient environment at VYNPS is not chemically polluted by vapors of sulfur dioxide or other similar substances and the external environment does not contain saltwater or high chlorides. Therefore, loss of material due to pitting and crevice corrosion is not an aging effect requiring management for aluminum and stainless steel components exposed to the external environment.

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Item Request Response 279 A-W-14 LRA Amendment LRA Table 3.5.1, Item Number 3.5.1-52, under the discussion column, states that loss of mechanical function due to the listed mechanisms is not an aging effect. Proper Loss of material due to corrosion is an aging effect that can cause a loss of intended design prevents distortion, overload,. and fatigue due to vibratory and cyclic thermal function. Loss of mechanical function would be considered a loss of intended loads. Explain how loss of mechanical function due to corrosion is not an aging effect function. Loss of mechanical function is not an aging effect, but is the result of which needs to be managed for the period of extended operation. If proper design aging effects. There have been component failures in the industry due to distortion, prevents distortion, overload, and fatigue due to vibratory and cyclic thermal loads, overload, and excessive vibration. Such failures typically result from inadequate explain if there has never been a component failure at VYNPS due to any of these design or events rather than the effects of aging. Failures due to cyclic thermal conditions. Explain if there has never been a component failure in the nuclear industry loads are very rare for structural supports due to their relatively low temperatures.

due to any of these conditions. Explain where sliding support bearing and sliding The sliding surface material used at VYNPS is lubrite, which is a corrosion resistant support surfaces are used in component groups B2 and B4 at VYNPS and provide the material. Components are inspected under ISI-IWF for torus saddle supports and environment they are exposed to. Structures Monitoring Program for the lubrite components of radial beam seats.

Plant operating experience has not identified failure of lubrite components used in structural applications. No current industry experience has identified failure associated with lubrite sliding surfaces. Components associated with B2 grouping are limited to the torus radial beam seats and support saddles. There are no sliding support surfaces associated with the B4 component grouping for sliding surfaces at VYNPS.

LRA Table 3.5.1, Item 3.5.1-52 will be revised to read as follows.

"Loss of mechanical function due to the listed mechanisms is not an aging effect.

Such failures typically result from inadequate design or operating events rather than from the effects of aging. Failures due to cyclic thermal loads are rare for structural supports due to their relatively low temperatures."

280 A-W-15 LRA Amendment LRA Table 3.5.1, Item Number 3.5.1-54, under the discussion column, states that loss of mechanical function due to the listed mechanisms is not an aging effect. Proper The discussion for Item Number 3.5.1-54 was not saying that failures have not design prevents distortion, overload, and fatigue due to vibratory and cyclic thermal occurred, but that loss of mechanical function is not an aging effect. For license loads. Explain how loss of mechanical function due to corrosion is not an aging effect renewal, Entergy identifies a number of aging effects that can cause loss of intended which needs to be managed for the period of extended operation. If proper design function. Loss of intended function includes loss of mechanical function. The loss prevents distortion, overload, and fatigue due to vibratory and cyclic thermal loads, of function is not considered an aging effect. Aging effects that could cause loss of explain if there has never been a component failure at VYNPS due to any of these mechanical function for components in Item Number 3.5.1-54 are addressed conditions. Explain if there has never been a component failure in the nuclear industry elsewhere in the aging management reviews. For example, loss of material due to due to any of these conditions. Explain what VYNPS inspects for during VT-3 visual any mechanism is addressed in Table 3.5.2-6 under listings for component and examinations of groups B1.1, B1.2 and B1.3 components under its Inservice Inspection piping supports ASME Class 1, 2, 3 and MC (Page 3.5-70), and component and Program during its current license and also anticipated VT-3 visual examinations during piping supports (Page 3.5-71). Component failures at VYNPS and in the nuclear its possible extended license period. industry have certainly occurred due to overload (typically caused by an event such as water hammer) or vibratory and cyclic thermal loads. Because of the low operating temperatures, failures due to cyclic thermal loads are extremely rare for structural commodities. Failures due to distortion or vibratory loads have also occurred due to inadequate design, but rarely if ever, due to the normal effects of aging.

LRA Table 3.5.1, Item 3.5.1-54 will be revised to state:

Loss of mechanical function due to distortion, dirt, overload, fatigue due to vibratory, and cyclic thermal loads is not an aging effect requiring management. Such failures typically result from inadequate design or events rather than the effects of aging.

Loss of material due to corrosion, which could cause loss of mechanical function, is addressed under Item 3.5.1-53 for Groups B1.1, B1.2, and B1.3 support members."

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Item Request Response 281 A-W-16 The NUREG-1801 referenced programs involve visual inspections and leak testing LRA Table 3.5.1, Item Number 3.5.1-10, under the discussion column, states that which are not optimum methods for managing SCC. Therefore, when possible, it is cracking due to stress corrosion cracking for stainless steel penetration sleeves and more appropriate to assess the conditions and identify whether the applicable aging penetration bellows is not applicable. Explain if the VYNPS Containment Inservice effects require management. As stated in section 3.5.2.2.1.7, stress corrosion Inspection Program and Containment Leak Rate Program are used currently to detect cracking is not an aging effect requiring management for the penetration sleeves cracking of stainless steel penetration sleeves and penetration bellows by inspection and bellows, since the conditions necessary for SCC do not exist.

and testing. Explain why it is not more appropriate to take credit for these two programs to detect cracking without the need for additional enhanced examinations However these components are evaluated for aging effects requiring management, then to say not applicable. such as cracking, as shown in Table 3.5.2-1 (Reference item for Drywell to torus vent line bellows).

282 A-W-17 LRA Amendment LRA Table 3.5.1, Item Number 3.5.1-34, under the discussion column, does not make reference to LRA Section 3.5.2.2.2.4 (1) for further evaluation. Explain why this link is NUREG-1800, Item Number 3.5.1-34 indicates that further evaluation is necessary not made to the further evaluation section. only for aggressive environments. No reference was provided to further evaluation in LRA Section 3.5.2.2.2.4 (1) since the VYNPS environment is not aggressive as noted in LRA Table 3.5.1, Item Number 3.5.1-34, under the discussion column.

LRA Table 3.5.1, Line Item 3.5.1-34 discussion will be revised to add "See Section 3.5.2.2.2.4(1)".

283 A-W-18 LRA Amendment LRA Table 3.5.1, Item Number 3.5.1-35, under the discussion column, does not make reference to LRA Section 3.5.2.2.2.4 (2) for further evaluation. Explain why this link is Due to an administrative error the reference to ACI should have been ACl 318 and not made to the further evaluation section. Provide a copy of ACI-301 as listed under not ACl 301. LRA Table 3.5.1, Item 3.5.1-35 discussion will be revised to refer to the discussion. ACl 318. For clarification, a reference to Section 3.5.2.2.2.4(2) will also be added to the discussion.

See also Response 284 284 A-W-19 LRA Amendment LRA Table 3.5.1, Item Number 3.5.1-36, under the discussion column, does not make reference to LRA Section 3.5.2.2.2.4 (3) for further evaluation. Explain why this link is LRA Table 3.5.1, Line item Number 3.5.1-36 discussion will be revised to read as not made to the further evaluation section. The statement: "See Section 3.5.2.2.2.1 (5) follows.

for additional discussion" needs further clarification that this section is for Groups 1-5, 7- Reaction with aggregates is not an applicable aging mechanism for VYNPS 9, however it would apply to accessible Group 6 concrete. Explain why LRA Section concrete components.

3.5.2.2.2.4 (3) lists cracking of concrete due to Stress Corrosion Cracking (SCC). See Section 3.5.2.2.2.1(5) (although for Groups 1-5, 7, 9 this discussion is also applicable for Group 6).

See Section 3.5.2.2.2.4(3) additional discussion. Nonetheless, the Structures Monitoring Program will confirm the absence of aging effects requiring management for VYNPS Group 6 concrete components.

Due to an administrative oversight, the heading of LRA Section 3.5.2.2.2.4 (3) inadvertently lists cracking of concrete due to Stress Corrosion Cracking (SCC).

This section heading should have begun with "Cracking Due to Expansion and Reaction with Aggregates...". Stress corrosion cracking is not discussed in the body, of this section.

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Item Request Response 285 A-W-20 LRA Amendment LRA Table 3.5.1, Item Number 3.5.1-37, under the discussion column, states not applicable and makes reference to Section 3.5.2.2.2.4(3). Section 3.5.2.2.2.4(3) For clarification, LRA Table 3.5.1, Item Number 3.5.1-37, will be revised to state the discusses inaccessible areas only. Explain why VYNPS under the discussion section following.

for Item Number 3.5.1-37 does not state: "Nonetheless, the Structures Monitoring "Not applicable. Nonetheless the Structures Monitoring Program will confirm the Program will confirm the absence of aging effects requiring management for VYNPS absence of aging effects requiring management for VYNPS Group 6 concrete Group 6 concrete components." This would apply to above grade concrete, like in Une components. See Section 3.5.2.2.2.4(3)".

Item 3.5.1-36 for accessible concrete.

286 A-W-21 LRA Amendment LRA Table 3.5.1, Item Number 3.5.1-40, under the discussion column, states: "Plant experience has not identified reduction in concrete anchor capacity or other concrete Building concrete at locations of expansion and grouted anchors; grout pads for aging mechanisms. Nonetheless, the Structures Monitoring Program will confirm support base plates are shown as "foundation" and "Reactor vessel support absence of aging effects requiring management for VYNPS concrete components." pedestal" in LRA Table 3.5.2-1 (page 3.5-54), "foundation" in Tables 3.5.2-2 thru The project team cannot find an AMR line item in Table 2 for this component (Building 3.5.2-5 (pages 3.5-58, 3.5-60, 3.5-62, and 3.5-66), and as 'Equipment concrete at locations of expansion and grouted anchors; grout pads for support base pads/foundations" in Table 3.5.2-6 (page 3.5-78). Further evaluation is provided in plates). Provide the Table 2 number, LRA page number, and component for where this LRA section 3.5.2.2.2.6(1), page 3.5-14.

AMR line item is evaluated and shown.

LRA Table 3.5.1, Item Number 3.5.1-40 discussion will be revised to add "See Section 3.5.2.2.2.6(1)".

287 3.1.1-19-P-02 The head seal leak detection lines are not part of the pressure vessel but are Please clarify the basis for omitting the leak-off lines themselves from Table 3.1.2-1. included in Table 3.1.2-3 with other reactor coolant pressure boundary piping. They are included on page 3.1-67 with piping and fittings <4"NPS. Plant specific note 104 identifies the applicability of this aging management review result to the leak detection line.

288 3.1.1-25-P-01 The jet pump sensing lines do not appear in Table 3.1.2-2 (Reactor Vessel Internals Please clarify the basis for omitting the jet pump sensing lines from Table 3.1.2-2 Summary of Aging Management Evaluation) because the jet pump sensing lines inside the vessel are not subject to aging management review. These lines are not required to maintain pressure boundary and hence have no license renewal intended function. The jet pump sensing lines outside the vessel are included with the piping <4" in Table 3.1.2-3.

289 3.1.1-40-P-02 Many NUREG-1801, Volume 2 items are very similar in terms of materials, On page 3.1-41, for the stainless incore housings, please confirm that the correct GALL environment, aging effect and aging management program. Where a NUREG-1 801 item is referenced. item lists the same component, the choice is straightforward. Where NUREG-1 801 does not match the specific component, the selection of the item to compare to the aging management review results is somewhat arbitrary. In this case, the components were considered a subset of the reactor vessel (hence the listing within the reactor vessel table) and the comparison was made to the cracking item within the NUREG-1801 BWR reactor vessel table that best (subjectively) represented the incore housings.

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Item Request Response ResDonse 290 3.1.1-41-P-02 The material for these components is identified as low allow steel with stainless On page 3.1-41 and 3.1-43, the GALL items referenced in this AMR are for stainless steel cladding. The material exposed to the internal environment of reactor coolant steel and nickel-based alloy components that may be subject to SCC. It does not (treated water) is the stainless steel cladding. When evaluating surface aging appear to be appropriate for low-alloy steel. Is there a more suitable GALL item? effects such as cracking and loss of material, the stainless steel cladding is the material that must match the NUREG-1801 item. NUREG-1801 item IV.A1-1 provides the best match for the material, environment and aging effect combination within the BWR reactor vessel table.

The applicable material for the external environment (air) is low alloy steel (or "steel" in NUREG-1801 terms).

291 3.1.1-41-P-04 LRA Amendment On page 3.1-52, the component type 'thermal sleeves, feedwater inlets (N4)' is managed using inservice inspection and water chemistry control - BWR. How are the The feedwater nozzle thermal sleeves are in Table 3.1.2-1 with an intended function thermal sleeves to be inspected? of pressure boundary. Cracking of the thermal sleeves is managed by Inservice Inspection and Water Chemistry Control - BWR.

Further review of the thermal sleeve design (to determine exactly how ISI inspects them) determined that the VY sleeves are not welded in place, rather they are an interference fit. As such, there is no weld to the pressure boundary piping that can be examined by ISI.

Given that there is no pressure boundary weld, these sleeves are not part of the pressure boundary. As such they have no intended function for License Renewal, and with no intended function they are not subject to aging management review1.

Therefore, Vermont Yankee will amend the License Renewal Application to indicate that the feedwater thermal sleeves are not subject to aging management review.

1 The feedwater thermal sleeves have no non-safety affecting safety related (a2) function. They are completely contained within the feedwater piping and cannot spray or leak on other equipment. The feedwater thermal sleeves are a part of the feedwater piping inside the vessel, and failure of that piping does not defeat the delivery of water to the vessel annulus, as any leakage also goes to the vessel annulus.

292 3.1.1-51-P-01 Same question on #217.

On page 3.1-60, the CASS jet pump castings exposed to treated water are managed.

Please confirm that GALL item IV.B1-11 applies, and whether there is a cast orificed fuel support or CRD component that is also managed this way.

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Item Request Response 293 3.3.1-32-K-01 LR Commitments 3 and 4 Beginning on page 3.3-94, many component types are managed using the diesel fuel LRA Amendment monitoring program. Please confirm that the VYNPS Diesel Fuel Monitoring AMP is consistent with GALL XI.M32, "One-Time Inspection," as well as with XI.M30, "Fuel Oil As stated in LRA Section 3.2.2.9, loss of material due to general, pitting, crevice, Chemistry." and MIC for carbon steel piping and components exposed to fuel oil is managed by the Diesel Fuel Monitoring Program. This program includes sampling and monitoring of fuel oil quality to ensure levels of water, particulates, and sediment remain within the specified limits. Maintaining parameters within limits ensures that significant loss of material will not occur. Ultrasonic inspection of storage tank bottoms where water and contaminants accumulate will be performed to confirm the effectiveness of the Diesel Fuel Monitoring Program. As stated in LRA Section B.1.9, the Diesel Fuel Monitoring Program is consistent with the program described in NUREG-1801,Section XI.M3, Fuel Oil Chemistry Program, with minor exceptions.

The Diesel Fuel Monitoring Program is not consistent with GALL XI:M32, "One-Time Inspection," nor are one-time inspections necessary to verify the effectiveness of the program. The Diesel Fuel Monitoring Program includes periodic cleaning, visual inspection, and ultrasonic inspection of storage tank bottoms where water and contaminants accumulate to confirm the effectiveness of the oil quality monitoring activities to preserve an environment that is not conducive to corrosion.

The One-Time Inspection program will be revised to include activities to confirm the effectiveness of the Oil Analysis and Diesel Fuel Monitoring programs.

LR Commitments 3 and 4 are provided for further clarification of componet testing.

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Item Request Response 294 3.3.1-33-K-01 LRA Amendment Beginning on page 3.3-71, several component types in a lube oil environment are managed using the VYNPS oil analysis program. Please confirm that the VYNPS Oil As stated in LRA Section 3.2.2.7, steel piping and components in auxiliary systems Analysis AMP is consistent with GALL XI.M32, "One-Time Inspection," as well as with at VYNPS that are exposed to lubricating oil are managed by the Oil Analysis XI.M39, "Lubricating Oil Analysis." See 3.3.1-14-K-01 Program, which includes periodic sampling and analysis of lubricating oil to maintain contaminants within acceptable limits, thereby preserving an environment that is not conducive to corrosion. As stated in LRA Section B.1.20, the Oil Analysis Program is consistent with the program described in NUREG-1 801,Section XI.M39, Lubricating Oil Analysis, with a minor exception.

The Oil Analysis Program is not consistent with GALL XI.M32, "One-Time Inspection," nor are one-time inspections necessary to verify the effectiveness of the program. Metals are not corroded by the hydrocarbon components of lubricants.

Lubricating oils are not good electrolytes and the oil film on the wetted surfaces of components tends to minimize the potential for corrosion. Corrosion in lube oil systems only occurs as the result of the presence of impurities or moisture.

Therefore, an effective oil analysis program, which maintains impurities and moisture below specified limits, precludes the need for one-time inspections.

Operating experience at VYNPS has confirmed the effectiveness of the Oil Analysis Program in maintaining moisture and impurities within limits such that corrosion has not and will not affect the intended functions of these components.

In numerous past precedents (including NUREG-1 828, Arkansas Nuclear One Unit 2 SER, Section 3.0.3.3.6, and NUREG-1831, Donald C. Cook SER, Section 3.0.3.3.8), the staff concluded that an effective oil analysis program, which maintains impurities and moisture below specified limits, is sufficient to demonstrate that the effects of aging will be adequately managed so that the intended functions will be maintained consistent with the current licensing basis for the period of extended operation.

The One-Time Inspection program will be revised to include activities to confirm the effectiveness of the Oil Analysis and Diesel Fuel Monitoring programs.

295 3.3.1-38-K-01 LRA Amendment Beginning on page 3.3-138, SCC of many stainless steel components exposed to reactor coolant above 140F is managed by the water chemistry - BWR program. LRA Table 3.3.2-11 includes stainless steel post-accident sampling system (PASS)

Provide documentation that demonstrates that these are outside the scope of the BWR sample line tubing and valves that are exposed to treated water or steam from the SCC program. Also, please clarify how the effectiveness of the AMP will be verified. reactor coolant system on internal surfaces. The components are less than 4" NPS (Since some of these components are <NPS 4, the review team understands that they and are outside the Class I reactor coolant system (RCS) pressure boundary. They are outside the scope of the BWR SCC program. However, it is not clear whether OTI are, therefore, outside the scope of the BWR SCC program. Aging of the PASS for small-bore piping will be used or the OTI included in the VYNPS water chemistry sample line tubing and valves is managed by the Water Chemistry Control - BWR programs. Program, which is verified by the One-Time Inspection Program. To provide further clarification, the effectiveness of the Water Chemistry Control - Auxiliary Systems, BWR, and Closed Cooling Water programs is confirmed by the One-Time Inspection program. This requires an amendment to the license renewal application to change the Appendix A, SAR supplementdescriptions for the Water Chemistry Control

-Auxiliary Systems, BWR and Closed Cooling Water programs to explicitly state One-Time Inspection Program activities will confirm the effectiveness of these programs. However, inspections performed under the small-bore piping activity, which applies to components within the Class-I RCS pressure boundary, will also provide data useful for evaluating the condition of these downstream components.

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Item Request Response 296 3.3.1-40-K-01 The tanks described on page 3.3-97 are diesel fuel oil tanks with external protective On page 3.3-97, a carbon steel tank is addressed. Please describe how the system coatings.

walkdown program will satisfy the recommendations of GALL AMP XI.M29, "Aboveground Steel Tanks." The attributes in GALL AMP XI.M29, "Aboveground Steel Tanks" include preventive measures to mitigate corrosion by protecting the external surface of steel tanks with paint or coatings in accordance with standard industry practice. This program relies on periodic system walkdowns to monitor degradation of the protective paint or coating. This program also monitors corrosion at inaccessible locations such as the tank bottom by thickness measurement.

The System Walkdown Program provides the preventive measures to protect the external accessible surfaces by visual inspection of carbon steel tanks to identify degradation of coatings, sealants, and caulking plus indications of leakage. Readily accessible tank surfaces are inspected at least once per refueling cycle and are normally performed more frequently.

Corrosion at inaccessible locations of the tank is addressed by thickness measurements conducted as part of the Diesel Fuel Monitoring Program. This program applies to the concrete (ext) environment for the tank bottom as shown on page 3.3-97.

Protective coatings on accessible external surfaces are repaired as part of the corrective action process following periodic inspection. Corrective action is taken as necessary on the tank bottom should minimum wall requirements not be maintained.

These combined actions satisfy the requirements of the GALL AMP XI.M29, "Aboveground Steel Tanks".

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Item Request Response 297 3.3.1-47-K-01 LRA Amendment Beginning on page 3.3-72, gray cast iron and carbon steel exposed to treated water is managed using the WC-CCW program. GALL recommends performance monitoring to The One-Time Inspection Program, described in LRA Section B.1.21 includes confirm the effectiveness of the CCCW program. Please identify an acceptable inspections to verify the effectiveness of the water chemistry control aging alternative method that will be used to verify the effectiveness of the WC - CCW management programs (Water Chemistry Control - Auxiliary Systems, Water program. Chemistry Control - BWR, and Water Chemistry Control - Closed Cooling Water) by confirming that unacceptable cracking, loss of material, and fouling is not occurring. As stated in LRA Section B.1.21, the One-Time Inspection Program is a new program which will be consistent with the program described in NUREG-1 801,Section XI.M32, "One-Time Inspection."

LRA Tables 3.1.1, 3.2.1, 3.3.1, and 3.4.1 indicate that the One-Time Inspection Program is credited along with the water chemistry control programs for line items for which GALL recommends a one-time inspection to confirm water chemistry control. For simplicity, the subsequent tables (Table 2's) do not list the One-Time Inspection Program each time a water chemistry control program is listed. However, since the One-Time Inspection Program is applicable to each water chemistry control program, it is also applicable to each line item that credits a water chemistry control program.

To provide further clarification, the effectiveness of the Water Chemistry Control -

Auxiliary Systems, BWR, and Closed Cooling Water programs is confirmed by the One-Time Inspection program. This requires an amendment to the license renewal application to change the Appendix A, SAR supplement descriptions for the Water Chemistry Control -Auxiliary Systems, BWR and Closed Cooling Water programs to explicitly state One-Time Inspection Program activities will confirm the effectiveness of these programs.

298 3.3.1-58-K-01 LR Commitment 30 On page 3.3-121, loss of material from external surfaces of a tank is managed using the system walkdown program instead of the fire protection program. Since the tank in This tank is in the C02 system. The system walkdown program was selected since question is in the FP system, please confirm that the FP AMP does not manage this it is the program that is the most used for managing external aging effects of aging effect. components in almost all systems similar to the External Surfaces Monitoring Program in GALL. Inspections in this program must be performed at least once per refueling. The GALL AMP XI.M26, Fire Protection requires visual inspection once every six months for C02 system components where the system walkdown frequency is once each refueling cycle. Since aging effects for this tank external surface in indoor air would be manifested over several years, it was determined that

.this variation in inspection frequency is not significant such that system walkdown was still appropriate.. However, per license renewal commitment 30, VYNPS will perform C02 system walkdowns every six months starting no later than the beginning of the period of.extended operation.

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Page 104 of 750

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Item Request Response 299 3.3.1-68-K-01 For components included for (a)(2) the pressure boundary function is two fold. The On page 3.3-194, loss of material from carbon steel components is managed using first is the pressure boundary of the passive component that ensures that the PS&PM. Please explain the intended function (pressure boundary) of the instrument air component cannot spatially interact through spray or leakage onto a safety related system and how it relates to the a(2) category to which the system has been assigned. components. The second applies for non-safety components connected to safety Also, please explain how this GALL v2 item was chosen, since it invokes a fire related components where the non-safety components provide structural support for protection AMP. the safety related such that loss of pressure boundary would be indicative of structural integrity. For the carbon steel components containing untreated water that are managed by PSPM the pressure boundary function is only for preventing spray or leakage.

The instrument air system is an auxiliary system. This GALL item was chosen because in chapter VII for Auxiliary systems it was the best match for a material, environment, aging effect combination. A note E was selected since a different program than Fire Protection was invoked.

300 3.3.1-68-K-02 LRA Amendment

[Original Question]

On page 3.3-213, loss of material from carbon steel components is managed using [Original Response]

OTI. Please explain how this GALL v2 item was chosen, and justify the use of OTI for The environment for these components is untreated water from the radwaste system carbon steel exposed to raw water as opposed to a periodic inspection. which is defined in table 3.0-1 of the LRA as water that was originally treated but

[Follow-up Question] now may contain contaminants. Carbon steel in treated water is not expected to Looking for commitment to do more than OTI for carbon steel exposed to raw water. experience any significant aging effects. As a result this untreated water environment is not expected to result in significant aging such as loss of material, however a one time inspection will be performed to confirm the absence of significant aging effects. If significant aging is found to be occurring the corrective action program will determine the need for future inspections including a periodic inspection or possible replacement.

This GALL line item was chosen since the radwaste system is an auxiliary system in GALL chapter VII. For the material, environment, and aging effect combination of this item, (where untreated water is equivalent to raw water) this line item was the most appropriate. A note E was selected since a different program was used. No LRA Amendment for the "original" question. See below.

[Follow-up Response]

The "untreated water" environment for the carbon steel and copper alloy radwaste system components in LRA Table 3.3.2-13-32 Is originally treated water that may now contain contaminants that could result in an aggressive environment.

Therefore, the aging management program will be changed from One-Time Inspection to Periodic Surveillance and Preventive Maintenance for managing loss of material for carbon steel and copper alloy components in the radwaste system exposed to untreated water (LRA Table 3.3.2-13-32).

This requires a change to the LRA.

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Item Request Response Resnonse 301 3.3.1-68-K-03 [Original Question]

[Follow-up Question] The comp6onents in question are in the potable water system. Potable water, though Looking for commitment to do more than OTI for carbon steel exposed to raw water. not treated in accordance with a GALL program such as water chemistry, is treated

[Original Question] to an extent before used at the site such that it is acceptable for human Beginning on page 3.3-206, loss of material from carbon steel components is managed consumption. However, since it is not monitored by the site it was identified as using OTI. Please justify the use of OTI for carbon steel exposed to raw water as untreated water which is defined in table 3.0-1 of the LRA as water that was opposed to a periodic inspection. originally treated but now may contain contaminants. Carbon steel in treated water is not expected to experience any significant aging effects. As a result this untreated water environment is not expected to result in significant aging such as loss of material which could impact the intended function of the component.

However a one time inspection will be performed to confirm the absence of significant aging effects. If significant aging is found to be occurring the corrective action program will determine the need for future inspections including a periodic inspection or possible replacement.

(New Response): The "untreated water" environment for the carbon steel potable water system components in LRA Table 3.3.2-13-29 Is not "raw water"; it is actually treated water. Water for this system comes from four onsite wells and is monitored and treated to meet the regulations of the state of Vermont. It was labeled "untreated water" because conductivity and dissolved oxygen are not monitored.

However, carbon steel is not expected to experience significant aging effects in a treated water environment. As indicated in the LRA, a One-Time Inspection of carbon steel potable water system components exposed to "untreated water" will be performed to confirm the absence of significant aging effects. Therefore, a commitment to do more to manage aging of these components is not necessary.

CLOSED TO RAI 3.3.1-68-K-03 302 3.3.1-69-K-01 The stainless steel filters and filter housings exposed to raw water on page 3.3-106 On page 3.3-104, loss of material from stainless steel components is managed using are filters that support the operation of the diesel fire pump by filtering the cooling FP. Please explain why the filter and filter housing are managed with the fire protection source to the engine. The Fire Protection Program performs tests and inspections program instead of the fire water system program. of the diesel engine and its support components and is therefore credited for management of these components.

303 3.3.1-70-K-01 The tubing exposed to raw water on page 3.3-106 supports the operation of the Beginning on page 3.3-106, loss of material from copper alloy components in raw water diesel fire pump by supplying the cooling water source to diesel engine. The Fire is managed using FP. Please explain why these components are managed with the fire Protection Program performs tests and inspections of the diesel engine and its protection program instead of the fire water system program. support components and therefore is credited for management of these components.

)

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Item Request ResDonse 304 3.3.1-70-K-02 LRA Amendment

[Follow-up Questions Looking for commitment to do more than OTI for carbon steel exposed to raw water. [Original Response]

(Original Question] The environment for these components is untreated water from the radwaste system On page 3.3-213, loss of material from copper alloy components in raw water is which is defined in table 3.0-1 of the LRA as water that was originally treated but managed using OTI. Please explain the basis for applying an OTI program instead of now may contain contaminants. Since this component is not in the fire protection the fire water system program. system the use of the fire protection program is not appropriate. Copper alloy in treated water is not expected to experience any significant aging effects. Because this untreated water began as treated water it is also not expected to result in significant aging such as loss of material which could impact the intended function of the component. However a one time inspection was chosen to confirm the absence of significant aging effects. If significant aging is found to be occurring the corrective action program will determine the need for future inspections including a periodic inspection or possible replacement.

(New Response) The "untreated water' environment for the carbon steel and copper alloy radwaste system components in LRA Table 3.3.2-13-32 Is originally treated water that may now contain contaminants that could result in an aggressive environment. Therefore, the aging management program will be changed from One-Time Inspection to Periodic Surveillance and Preventive Maintenance for managing loss of material for carbon steel and copper alloy components in the radwaste system exposed to untreated water (LRA Table 3.3.2-13-32).

305 3.3.1-83-K-01 The heat exchangers represented are the fire pump diesel jacket water heat On page 3.3-107, fouling of copper alloy heat exchanger tubes in raw water is managed exchanger and the gear box oil cooler. Both heat exchangers use water from the using FP, where GALL suggests OCCW. Please identify the specific heat exchanger to fire water system (raw water) for cooling. The Fire Protection Program performs which this AMR applies, and the basis for the choice of AMP. tests and inspections of the diesel engine. Since these heat exchangers are part of the fire diesel it is appropriate to manage fouling with the Fire Protection Program which tests the engine and its auxiliaries.

306 3.3.2-04-01 -K-01 These fins are part of the emergency diesel generator air coolers that are reviewed On page 3.3-78, fouling of aluminum heat exchanger fins in air is managed using PSM. in VY-AMRM-13. The diesel generators are tested periodically in procedure OP Please provide the procedure under which fouling is monitored. 4126 "Diesel Generators Surveillance". This is an extensive test procedure that includes verification of local diesel operating conditions including the intercooler air temperature during diesel operation. The monitoring of this temperature within temperature limits confirms the proper operation of the intercooler which provides the indication that fouling that can impact the diesel performing its intended function is not occurring. The data is recorded in the Diesel Generator Operating Data" at the end of OP4126 and page 1 of 6 has the intercooler air temperature with normal range and acceptance criteria shown.

307 3.3.2-04-03-K-01 These tubes are part of the emergency diesel generator air coolers that are On page 3.3-79, fouling of copper exchanger tubes in air is managed using PSM. reviewed in VY-AMRM-13. The diesel generators are tested periodically in Please provide the procedure under which fouling is monitored. procedure OP 4126 "Diesel Generators Surveillance". This is an extensive test procedure that includes verification of local diesel operating conditions including the intercooler air temperature during diesel operation. The monitoring of this temperature within temperature limits confirms the proper operation of the intercooler which provides the indication that fouling that can impact the diesel performing its intended function is not occurring.

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Item Request Response 308 B.1.16-P-02 The Instrument Air Quality program at VYNPS is a plant specific program.

GALL recommends an AMP that is consistent with GALL AMP XI.M24, "Compressed Air Monitoring." VYNPS uses a plant specific AMP, B.1.16, Instrument Air Monitoring Through monitoring of air quality, the Instrument Air Quality Program maintains Program," which does not include the pressure testing that is suggested by the GALL instrument air free of significant contaminants and water, thereby preventing loss of AMP. What program will be used to perform pressure testing of the instrument air material. This approach to manage loss of material is more effective than leakage system? monitoring using pressure testing. Pressure testing of components detects leakage that would be an indication of loss of the pressure boundary intended function. This testing does not ensure that their passive intended function of maintaining pressure boundary is managed. As a result, the Instrument Air Quality program at VYNPS.

does not include pressure testing of components. However, by maintaining the instrument air system free of significant contaminants and water, the Instrument Air Quality Program is more effective than pressure testing for managing loss of material in the instrument air system.

309 3.1.1-01-P-02 LRA Amendment Generic Question 1: VY LRA identified that cracking fatigue credits TLAA - metal fatigue for almost all the components in RCS (Section 3.1). In Appendix C, BWRVIP Under Entergy's approach, the Section 3 table entries listing Cracking-fatigue with applicant's action items (AAIs) identified that there is no plant-specific TLAAs. Please TLAA - metal fatigue only indicate that the component meets the screening criteria clarify the difference between AMR and AAIs. (temperature) for fatigue, and should be reviewed to determine the existence of TLAA (metal fatigue analyses). That review is documented in Section 4 of the LRA.

Note: This question applied to all Sections (3.1 thru 3.6). If TLAA was credited in the LRA, the TLAA analysis should be available to support the AMR. Based on requirements of the license renewal rule, Section 4 includes discussion of only those entries that concluded there were associated TLAA. This resulted in numerous "TLAA - metal fatigue entries in Section 3 with no corresponding discussion in Section 4.

Entergy will modify the tables in Section 3 to delete the "TLAA - metal fatigue" entries for which there is no TLAA discussed in Section 4.

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Item Request Response 310 B.3.2.2-H1-01 LRA Amendment In LRA Table 3.2.2-1 on page 3.2-34, the applicant proposed to manage the loss of material of carbon steel, in a treated water environment, using Water Chemistry As stated in LRA Section B.1.30.2, the Water Chemistry Control - BWR Program is Control - BWR Program. NUREG-1801 recommends the Water Chemistry Control - consistent with the program described in NUREG-1801,Section XI.M2, "Water BWR along with a One-Time Inspection Program. The staff request the applicant Chemistry." The One-Time Inspection Program, described in LRA Section B.1.21 provide justification for only using the Water Chemistry Control - BWR Program. includes inspections to verify the effectiveness of the water chemistry control aging management programs (Water Chemistry Control - Auxiliary Systems, Water Chemistry Control - BWR, and Water Chemistry Control - Closed Cooling Water) by confirming that unacceptable cracking, loss of material, and fouling is not occurring. As stated in LRA Section B.1.21, the One-Time Inspection Program is a new program which will be consistent with the program described in NUREG-1 801,Section XI.M32, "One-Time Inspection."

LRA Tables 3.1.1, 3.2.1, 3.3.1, and 3.4.1 indicate that the One-Time Inspection Program is credited along with the water chemistry control programs for line items for which GALL recommends a one-time inspection to confirm water chemistry control. For simplicity, the subsequent tables (Table 2's) do not list the One-Time Inspection Program each time a water chemistry control program is listed. However, since the One-Time Inspection Program is applicable to each water chemistry control program, it is also applicable to each line item that credits a water chemistry control program.

To provide further clarification of the Water Chemistry Control - Auxiliary Systems, BWR, and Closed Cooling Water programs is confirmed by the One-Time Inspection program. This requires an amendment to the license renewal application to change the Appendix A, SAR supplement descriptions for the Water Chemistry Control -

Auxiliary Systems, BWR and Closed Cooling Water programs to explicitly state One-Time Inspection Program activities will confirm the effectiveness of these programs.

311 B.3.2.2-H1-02 The component in question is assumed to be the cyclone separator with an aging In LRA Table 3.2.2-1 on page 3.2-33, the applicant proposed using the Water effect of cracking that credits GALL line item V.D2-29. The GALL line item chosen Chemistry Control - BWR Program to manage cracking in treated water environment. for this component specifies the BWR SCC program in addition to Water Please give justification why the Aging Management Program credited is not in Chemistry. The BWR SCC program is applicable to all BWR piping and piping accordance with the NUREG-1 801 recommended program. welds made of austenitic SS and nickel alloy that is 4 in. or larger in nominal diameter and contains reactor coolant at a temperature above 93°C (200'F) during power operation, regardless of code classification. The components included in this line item are less than 4" NPS and are outside the reactor coolant system (RCS) pressure boundary. They are, therefore, outside the scope of the BWR SCC program. As a result the Water Chemistry Control - BWR program is used alone.

As stated in LRA Section B.1.30.2, the Water Chemistry Control - BWR Program is consistent with the program described in NUREG-1 801,Section XI.M2, "Water Chemistry." The One-Time Inspection Program, described in LRA Section B.1.21 includes inspections to verify the effectiveness of the water chemistry control aging management programs (Water Chemistry Control - Auxiliary Systems, Water Chemistry Control - BWR, and Water Chemistry Control - Closed Cooling Water) by confirming that unacceptable cracking, loss of material, and fouling is not occurring.

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Item Request Response 312 B.3.2.2-H1-03 LRA Amendment In LRA Table 3.2.2-1 on page 3.2-34, the applicant proposed to manage the loss of material of gray cast iron, in a treated water environment, using Water Chemistry As stated in LRA Section B.1.20.3, passive intended functions of pumps, heat Control - Closed Cooling Water Program. The applicant states the program is exchangers and other components will be adequately managed by the Water consistent with NUREG-1 801 with one exception, there is not performance and Chemistry Control - Closed Cooling Water Program through monitoring and control functional testing. The staff request the applicant provide justification on why the Water of water chemistry parameters. Control of water chemistry ensures that loss of Chemistry Control - Closed Cooling Water Program is used for this line item. material will not occur in gray cast iron components in a treated water environment.

Also the one-time inspection program described in LRA Section B.1.21 includes inspections to verify the effectiveness of all the water chemistry control aging management programs by confirming that unacceptable cracking, loss of material, and fouling is not occurring. In most cases, functional and performance testing verifies that component active functions can be accomplished and as such would be included as part of Maintenance Rule (10CFR50.65). Passive intended functions of pumps, heat exchangers and other components will be adequately managed by the closed cooling water chemistry program through monitoring and control of water chemistry parameters. The use of the Water Chemistry Control - Closed Cooling Water and One time inspection programs are effective programs to manage loss of material for gray cast iron in a treated water environment.

To provide further clarification of the Water Chemistry Control - Auxiliary Systems, BWR, and Closed Cooling Water programs is confirmed by the One-Time Inspection program. This requires an amendment to the license renewal application to change the Appendix A, SAR supplement descriptions for the Water Chemistry Control -

Auxiliary Systems, BWR and Closed Cooling Water programs to explicitly state One-Time Inspection Program activities will confirm the effectiveness of these programs.

313 B.3.2.2-H1-04 LRA Amendment In Section 3.2 of the LRA the applicant uses Water Chemistry Control - Closed Cooling Water Program as an Aging Management Program. The program is stated to be To provide further clarification of the Water Chemistry Control - Auxiliary Systems, consistent with NUREG-1801 Closed Cycle-Cooling Water System with one exception. BWR, and Closed Cooling Water programs is confirmed by the One-Time Inspection Please provide justification why the Water Chemistry Control - Closed Cooling Water program. This requires an amendment to the license renewal application to change Program is used without the recommended testing and inspection to monitor the effects the Appendix A, SAR supplement descriptions for the Water Chemistry Control -

of corrosion and SCC on the intended function of components. Auxiliary Systems, BWR and Closed Cooling Water programs to explicitly state One-Time Inspection Program activities will confirm the effectiveness of these programs.

314 B.3.2.2-H1-05 It cannot be determined exactly which line items are referred to but the BWR SCC In Table 3.2 in Section 3.2 of the LRA the applicant uses Water Chemistry Control - program is applicable to all BWR piping and piping welds made of austenitic SS and BWR Program to manage the aging effect of cracking on stainless steel material. nickel alloy that is 4 in. or larger in nominal diameter and contains reactor coolant at NUREG-1801 recommends Water Chemistry and BWR Stress Corrosion Cracking a temperature above 93°C (200'F) during power operation, regardless of code Program. Please provide justification why the applicant is not in accordance with the classification. The piping components included in section 3.2 with temperatures recommended NUREG-1801. above 200 this line item are less than 4" NPS and are outside the reactor coolant system (RCS) pressure boundary. They are, therefore, outside the scope of the BWR SCC program. As a result the Water Chemistry Control - BWR program is used alone. As stated in LRA Section B.1.30.2, the Water Chemistry Control -

BWR Program is consistent with the program described in NUREG-1801,Section XI.M2, "Water Chemistry." The One-Time Inspection Program, described in LRA Section B.1.21 includes inspections to verify the effectiveness of the water chemistry control aging management programs (Water Chemistry Control - Auxiliary Systems, Water Chemistry Control - BWR, and Water Chemistry Control - Closed Cooling Water) by confirming that unacceptable cracking, loss of material, and fouling is not occurring.

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Item Request Response 315 B.3.2.2-H1-06 LRA Amendment In Table 3.2.2-4 in Section 3.2 of the LRA, the applicant uses Oil Analysis Program to manage carbon steel in a lube oil environment with loss of material as the aging effect. As stated in LRA Section 3.2.2.7, steel piping and components in auxiliary systems Please provide justification to the staff why the Table 2 line items do not have an at VYNPS that are exposed to lubricating oil are managed by the Oil Analysis inspection program to evaluate detection of aging effects as recommended by NUREG- Program, which includes periodic sampling and analysis of lubricating oil to maintain 1801. contaminants within acceptable limits, thereby preserving an environment that is not conducive to corrosion. As stated in LRA Section B.1.20, the Oil Analysis Program is consistent with the program described in NUREG-1801,Section XI.M39, Lubricating Oil Analysis, with a minor exception.

The Oil Analysis Program is not consistent with GALL XI.M32, "One-Time Inspection," nor are one-time inspections necessary to verify the effectiveness of the program. Metals are not corroded by the hydrocarbon components of lubricants.

Lubricating oils are not good electrolytes and the oil film on the wetted surfaces of components tend to minimize the potential for corrosion. Corrosion in lube oil systems only occurs as the result of the presence of impurities or moisture.

Therefore, an effective oil analysis program, which maintains impurities and moisture below specified limits, precludes the need for one-time inspections.

Operating experience at VYNPS has confirmed the effectiveness of the Oil Analysis Program in maintaining moisture and impurities within limits such that corrosion has not and will not affect the intended functions of these components.

In numerous past precedents (including NUREG-1828, Arkansas Nuclear One Unit 2 SER, Section 3.0.3.3.6, and NUREG-1 831, Donald C. Cook SER, Section 3.0.3.3.8), the staff concluded that an effective oil analysis program, which maintains impurities and moisture below specified limits, is sufficient to demonstrate that the effects of aging will be adequately managed so that the intended functions will be maintained consistent with the current licensing basis for the period of extended operation.

The One-Time Inspection program will be revised to include activities to confirm the effectiveness of the Oil Analysis and Diesel Fuel Monitoring programs.

316 When Entergy Vermont Yankee (ENVY) goes to the period of extended operation, how VYNPS will continue to use the analysis and evaluation techniques described in 10 will ENVY analyze and evaluate the equipment in the Electrical Equipment Qualification CFR 50.49 and IEEE 323. The equipment in the EQ program is both active and (EQ) program for 60 years per 10 CFR 54.21? Include in the response that the passive. The EQ program documentation has recently been updated to reflect the environmental conditions (both ambient and accident) resulting from EPU will be used normal and accident environments under EPU conditions. The program considers as the bases for the analysis and evaluation going forward. Also confirm that the equipment degradation from EPU radiation dose, normal and accident (LOCA, approach described in the response to this question is consistent with the ENVY LRA. HELB) temperatures as well as cycling, pressure, humidity, etc.

For the period of extended operation, the EQ program requires VYNPS to update the EQ documentation to reflect the additional service life. The environmental conditions (both ambient and accident) resulting from EPU are the basis for evaluations and analysis going forward.

This is consistent with the description of the EQ program in the VYNPS LRA.

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Item Request ResDonse 317 LRA-4.6 Torus Piping a. Per the MPR 751 excerpt provided below, all domestic Mark 1 BWRs appear to

a. Is VY bounded by MPR 751? Please provide a statement indicating that the estimate meet MPR 751 for both current operating and license renewal terms. It should be of the total number of 60 year SRV actuations used in the design fatigue analysis noted that VY-SRV operation has been very low and therefore SRV valve cycling remains valid and conservative, based on the actual SRV actuations counted through and related attached piping has been very low. VY has not had a leaking SRV's 2005. since the early 1980's. VY only functionally tests its SRVs once per cycle during

b. Is VY still bounded by MPR 751 after power uprate? reactor shutdown. Based on discussions with Operations, VY has had two SRV actuations events of note e.g.:

- Loss of Normal Power Event (1990).

- Loss of Switchyard Insulator Event (2005).

VY replaces all of its 4 installed SRVs every refueling cycle with readied spares.

This refurbishment strategy has ensured that inadvertent SRV operation has been minimized.

MPR-751 - Results and Conclusions Relevant to SRV piping (To NRC by GE letter MFN-187-82 dated 11/30/82).

3.0 RESULTS AND CONCLUSIONS This section contains the results of the fatigue evaluations performed on over 30 torus piping systems. These systems were selected by each A/E as representative of the most highly stressed torus piping systems in their respective plants. Thirty percent of these were SRV discharge lines and the remainder were lines attached to the torus with sizes ranging from 2-inch to 24-inch. All torus piping systems had a fatigue usage less than 0.5. The fatigue evaluation results, which are tabulated in Table 3-1, are summarized as follows:

SRV Discharge Piping:

Percent less than 0.3 fatigue usage - 72.7%

Percent less than 0.5 fatigue usage - 100%

A very conservative methodology has been developed for fatigue analysis of Mark I Class 2 piping. The fact that the calculated fatigue usage factors are low coupled with the very conservative approach used to develop the fatigue analysis methodology shows that fatigue is not a concern for attached piping. Thus this report answers the concern expressed by the NRC regarding the effect of cyclic mechanical loads on fatigue. Accordingly, there is no need for a complete evaluation of torus piping fatigue on a plant-unique basis.

B. Yes. There are no significant changes in the function or performance of the SRVs for EPU conditions. The SRV sizes, Rx dome pressure, SRV set points remain the same as for original licensed power. Also, checked flow conditions at the exit of the SRVs limits any significant increase in flow for the SRV discharge piping. Reference VY-RPT-05-00087, Rev.0, EPU Task Report for ER 04-1409.

Additional Information:

Based on a review of plant operating records, VYNPS has estimated approximately 150 actuations of a safety relief valve in 35 years of operation. Extrapolating this number to 60 years gives less that 260 lifts, or less than 65 lifts per valve. This is less than 1% of the analyzed 7500 lifts.

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Item Request Response 318 The CUF values in LRA Table 4.3-1 that are based on NUREG CR 6260 are not LR Commitment 27 applicable to VY and need to be removed and the issue addressed. LRA Amendment Please clarify the commitment made to perform a fatigue re-analysis to be used to LRA table 4.3-1 'will be amended to remove the NUREG/CR-6260 values. LRA table address environmental impact. The re-analysis needs to be made to a single code date. 4.3-3 will be amended to enter "NA" for.the CUFs for the core spray safe end, feedwater piping, RHR return piping, and RR piping tee entries. VYNPS will replace these entries with VYNPS-specific values as discussed below.

For the NUREG/CR-6260 locations, VYNPS will determine CUFs incorporating the potential effects of reactor water environment by applying Fen factors to valid CUFs determined by one of the following methods.

1E]For locations with existing fatigue analysis, use the existing CUF.

20More limiting VYNPS-specific locations with a valid CUF may be substituted for the NUREG/CR-6260 locations.

3E0Representative CUF values from other plants or from NUREG/CR-6260 may be used if they are adjusted to or envelope the VYNPS-specific external loads.

40An analysis using an NRC-approved version of the ASME code may be performed for the NUREG/CR-6260 location to determine a valid CUF.

Commitment 27 will be revised to indicate a due date of 2 years prior to the period of extended operation and to include reference to performing the analysis to an NRC-approved version of the ASME code.

319 LRA Page 4.3-3 and 4 - LRA Amendment A) Discuss how VY developed the condensed list of transients provided in Table 4.3-2 .A) The condensed list of transients in Table 4.3-2 was developed to simplify cycle from the complete list in the design spec. Also provide a copy of the design-spec(s) with tracking by the plant operations staff. The basis for reducing the number of the complete list of transients for NRC review. transients tracked is contained in Calculations VYC-378 Rev.0 and Rev.1.

Attachment 1 of VYC-378 Rev.1 is titled "Recommendations for Tracking/Limiting B) LRA Pg 4.3-4 Modify the statement on the bottom of Pg 4.3-4 that the TLAA Reactor Transient Events for Vermont Yankee Nuclear Power Station, November remains valid except for exceptions where CUF including EAF for 60 years exceed 1.0. 13,1987. The complete list of design transients is contained in Attachment 1 pgs 24 Please discuss the exceptions. to 27 and 31 to 32. Copies of VYC-378 Rev.0 and Rev.1 were provided for review.

The updated Reactor Vessel Specification for Extended Power Uprate is GE Specification No. 26A6019 Rev.1 dated 6/2/2003. It is supplemented by the original GE Reactor Vessel Design Specification No. 21A1115 Rev.4 issued 10/21//69.

Copies of both specifications were provided for review.

B) The last paragraph of Section 4.3.1.1 will be clarified as follows.

The VYNPS Fatigue Monitoring Program will assure that the allowed number of transient cycles is not exceeded. The program requires corrective action if transient cycle limits are approached. Consequently, the TLAA (fatigue analyses) based on those transients will remain valid for the period of extended operation in accordance with 10 CFR 54.21 (c)(1)(i). However, when the effects of reactor coolant environment on fatigue are added to the existing fatigue analyses, several locations have a projected cumulative usage factor in excess of 1.0. See section 4.3.3 for further discussion of the effects of reactor water environment on fatigue.

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Item Request Response ResDonse 320 LRA Page 4.3-5 LRA Amendment Ensure that Reference 4.3-1 is correct. If not, provide the correct reference. The correct reference is letter BVY96-96, not 96-48. The originator, addressee, title and date were correct, only the letter number was wrong. The following is the correct citation for Reference 4.3-1.

4.3-1 Sojka, R. E. (VYNPS), to USNRC Document Control Desk, "Response to Request for Additional Information Regarding Vermont Yankee Core Shroud Modification," BVY 96- 96, letter dated August 7, 1996.

321 LRA Section 4.3.1.2 - Reconcile/revise the discrepancy in Section 3 tables and Section LRA Amendment 4.0 on whether a plant-specific analysis is performed.

Tables 3.1.2-1, 3.1.2-2, and 3.1.2-3 will be revised to eliminate 'T-LAA - metal fatigue" whenever there is no corresponding TLAA in Section 4.0.

This requires an amendment to the LRA.

Close item to #309.

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Item Reauest Response 322 LRA Section 4.3.1.3 - Table 4.3-1 stated that piping that no plant specific fatigue LRA Amendment analysis was found/performed for RHR to RR Tee. However, Section 4.3.1.3 says that such analysis was performed. Please resolve this discrepancy. The statement in Section 4.3.1.3 was taken from GE calculations 23A5569 (RR Loop A Stress Analysis) and 23A5570 (RR Loop B Stress Analysis). Upon review of the RR piping replacement project records, no such fatigue analyses were located.

The statement wasmade as part of the GE template for these calculations as many plants were replacing the RR piping to the ASME Section III code. VYNPS replaced their piping to the original B31.1 code rather than ASME Section III and no plant specific analysis was performed for VYNPS. Unfortunately the statement was not deleted from the report and the statement was then quoted in the LR application.

This requires an amendment to the LRA to achieve consistency between Section 4.3.1.3 and Table 4.3-1.

In addition, we will modify section 4.3.2 to make changes consistent with 4.3.1.3.

We will add a statement summarizing Section 2.2.2 of LRPD-06 that none of the non-class 1 non-piping components have TLAA.

Section 4.3.1.3 and 4.3.2 should read as follows.

4.3.1.3 Class 1 Piping and Components VYNPS replaced reactor recirculation (RR) system piping in 1986. Also replaced were connecting portions of the residual heat removal (RHR) system piping. The new piping was designed and analyzed to ANSI B31.1 but was inspected and tested to ASME Section III requirements. Stress analyses for the reactor recirculation system were performed to B31.1 requirements. B31.1 does not require a detailed fatigue analysis that calculates a CUF, but allows up to 7000 cycles with a stress reduction factor of 1.0 in the stress analyses. The 7000 thermal cycle assumption is valid and bounding for 60 years of operation. Therefore, the pipe stress calculations are valid for the period of extended operation in accordance with 10 CFR 54.21 (c)(1)(i).

There are no TLAA for Class 1 non-piping components other than the reactor vessel as none of them are designed to codes that require fatigue analyses.

UFSAR Section 4.6.3 states that the main steam isolation valves are designed for 40 years based on 100 cycles of operation the first year and 50 cycles of operation per year thereafter. This statement may be interpreted to imply a TLAA. This TLAA will remain valid through the period of extended operation per 10 CFR 54.21 (c)(1)(i).

The MSIVs will not exceed 2050 cycles in 60 years (34 cycles per year).

4.3.2 Non-Class 1 Fatigue The design of safety class 2 and 3 piping systems incorporates the Code stress reduction factor for determining acceptability of piping design with respect to thermal stresses. The design of ASME B31.1 Code piping also incorporates stress reduction factors based upon an assumed number of thermal cycles. In general, 7000 thermal cycles are assumed, leading to a stress reduction factor of 1.0 in the stress analyses. VYNPS evaluated the validity of this assumption for 60 years of plant operation. The results of this evaluation indicate that the 7000 thermal cycle assumption is valid and bounding for 60 years of operation. Therefore, the pipe stress calculations are valid for the period of extended operation in accordance with 10 CFR 54.21 (c)(1)(i).

There are no TLAA for any non-class 1 non-piping components as none of them are built to codes that require fatigue analyses.

Some applicants for license renewal have estimated that piping in the primary sampling system will have more than 7000 thermal cycles before the end of the PM Page 115 of 150 11/14/20071:38:00 1111412007 1:38.00 PM Page 115 of 150

Item Request Response period of extended operation. The sampling system is used to take reactor coolant samples every 96 hours0.00111 days 0.0267 hours 1.587302e-4 weeks 3.6528e-5 months during normal operation. However, the normal samples are taken from the RWCU filter influent, where the water has already been cooled. Thus normal sampling does not cause a thermal cycle. Alternate samples may be taken directly from the B discharge header of the reactor recirculation system via containment penetration X-41; however, this is an infrequently performed procedure and this piping, designed to ASME B31.1, will not exceed 7000 cycles prior to 60 years of operation.

The deletion of the RHR to RR tee CUF from table 4.3-3 will leave a blank for this component. Other deletions will be made from this table per database question 318. VYNPS will complete the table per License Renewal commitment #27 as explained in response to item 318.

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Item Request Response 323 Does VY plan to perform Environmentally Assisted Fatigue (EAF) on plant specific VY plans to review the NUREG-6260 locations versus the VY plant configuration, locations or NUREG 6260 locations? and confirm whether they represent the limiting locations for VY. VY will then calculate Environmentally Assisted Fatigue (EAF) Cumulative Usage Factors Does the revised FW nozzle analysis (Table 4.3-3) include high cycle fatigue? If not, (CUFs) for the NUREG-6260 locations and supplement these with plant-specific please explain why. limiting locations as required. See Commitment No. 27.

The revised FW nozzle analysis, documented in Structural Integrity Associates Report SIR-04-020, does not include high cycle fatigue. The analysis evaluates the feedwater nozzle for the design transients contained in GE specifications No.

21A1115, "Reactor Pressure Vessel", and No. 26A6019, Revision 1, " Reactor Vessel - Extended Power Uprate". The design transients do not include "high cycle" fatigue.

High cycle fatigue in BWR Feedwater nozzles is attributable to leakage of relatively cold feedwater around the thermal sleeve mixing with the hot water in the annulus retuming from the steam dryer and steam separator. The mixing of the cold feedwater and the hot water in the annulus results in rapid thermal cycling in the nozzle blend (inner radius) region. The rapid thermal cycling causes cracks to develop in the stainless steel clad on the blend radius. Subsequent system cycling can cause these surface cracks to grow into the nozzle base metal.

In response to Generic Letter 80-095 and NUREG-0619, VY performs inspections on the feedwater nozzles. To support the inspection frequency requirements, calculation VYC-1 005, "Crack Growth Calculation for Vermont Yankee Feedwater Nozzles" was developed. This calculation is a fatigue crack growth calculation of a postulated flaw in the blend region. Inspections are scheduled prior to the postulated flaw growing to 20% of the ASME Section Xl maximum allowable flaw size. The current version of the calculation is VYC-1005, Revision 2. The methodology used is in compliance with GE BWR Owners Group Topical Report "Alternate BWR Feedwater Nozzle Inspection Requirements", GE-NE-523-A71-0594, Revision 1, August 1999, and the NRC Final Safety Evaluation (TAC No.

MA6787) dated March 10, 2000.

In summary, VYNPS manages this aging by monitoring system thermal cycles and periodically inspecting to assure cracking has not initiated. The NRC has previously reviewed and approved this approach, reference Letter D.H. Dorman (USNRC) to D.A Reid (VYNPC),

Subject:

Evaluation of Request for Relief from NUREG-0619 for VYNPS dated 2/6/95, (TAC No. M88803).

CLOSED TO RAI 4.3-H-02 324 GE Spec - Clarify how code case N-415 on alternate rules for pressure relief devices The reference in T0302 is not to an ASME Code Case; it is to paragraph N-415 of relates to fatigue evaluation described in the final T0302 Vessel Integrity Report. Section IIIof the 1965 version of the code. Section N-415 is titled "Analysis of Cyclic Operation" and is applicable as referenced.

325 GE Spec - Provide for review only, proprietary versions of Copies of these reports have been provided.

NEDC-32424P-A (Reference 1.1)

NEDC-32523P-A (Reference 1.2)

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Item Reauest Response Resnonse 326 Please provide the fatigue analysis as referenced in the EPU-FSAR: There is no reactor vessel internals fatigue analysis using the 1986 ASME Section IIIcode as a guideline. The fatigue analysis listed in the PUSAR is Task 0303 and it

- PUSAR Table 3.7 references NEDC-32424P-A and NEDC-32523P-A; copies of these analyses were provided in response to question 325.

327 Do you have any plans to use "Fatigue-Pro" other than for cycle counting? If so, explain Current plans for implementing FatiguePro at VY are to use Stress Based Fatigue and supplement application as appropriate. (SBF) monitoring for the Feedwater Nozzles. Automated or manual cycle counting (CBF) are planned for the remaining components. Components identified for automated CBF were selected using the following criteria; components with a design basis usage factor greater 0.40 for 40 yrs, Class 1 piping components or where field experience suggests that a fatigue concern exists.

The transient data acquisition capabilities in FatiguePro may be used for future development of SBF models and/or operational transient cycle counting for components as required to address operational changes and/or environmentally assisted fatigue concerns.

328 B.1.13-M-01 Provided RFO 25 (Fall 2005) large bore inspection report evaluations for inspection The staff has discovered, as a result of previous discussions with the applicant, that the nos. 2005 -01, 2005-02, 2005-09, 2005-10,2005-36, and 2005-37: and small bore VY FAC program calculations are very specific in terms of calculations, as compared evaluations 05-SB02 and 05_SB03. Also provided a copy of RFO outage inspection to other wall thickness applicants that we have reviewed. Please provide us with a report VY-RPT-06-000002 Rev.0.

couple of examples of these calculations.

329 B.113-M-02 Provided scoping / planning worksheets for both RFO 25 and RFO 26. These list The staff has also noted in their review of the LRA, that the VY program operational FAC industry OE evaluation for VY.

experience appears to be above average in discovery and identification of FAC-related issues. Please provide us with a couple of examples of piping FAC discovery using the present program.

330 3.1.1-19-P-03 LR Commitment 16 How does Vermont Yankee do volumetric examinations of small bore piping socket welds? VYNPS performs visual examinations of these welds as required by Section Xl of the ASME code.

The One-Time Inspection program will also include destructive or non-destructive examination of one (1) socket welded connection using techniques proven by past industry experience to be effective for the identification of cracking in small bore socket welds. Should an inspection opportunity not occur (e.g., socket weld failure or socket weld replacement), a susceptible small-bore socket weld will be examined either destructively or non-destructively prior to entering the period of extended operation.

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Item Request Response 331 3.2.2-H1i.07 LR Commitment 34 In Table3.2.2-1 of Section 3.2 in the LRA System Walkdown Program is used to. LRA Amendment manage loss of material in the bolting components. Please provide justification why System Walkdown Program instead of NUREG-1801 is recommended Bolting Integrity The System Walkdown Program is used to manage loss of material in bolting Program. through the use of visual inspections that are performed at least once per refueling cycle. The GALL Bolting Integrity Program XI.M18 also credits the system walkdown program for the detection of leakage in bolted joints which could lead to loss of material but does not specify an inspection frequency. The application of the System Walkdown program to manage loss of material is therefore consistent with the GALL XI.M18 program.

In addition, a Bolting Integrity Program is in development that will address the aging management of bolting in the scope of license renewal. The Bolting Integrity Program will be implemented prior to the period of extended operation in accordance with commitment number 34.

Additional information for the Bolting Intergity Program is provided in LRA Amendments 18 and 23.

332 3.2;2-H1-08 The component in question is the heat exchanger tubes in the RHR heat In Table 3.2.2-1 on Page 3.2-35 of the LRA, can the applicant provide justification why exchanger. These tubes are cooled by service water and can be exposed to Service Water Integrity Program is used to manage cracking in stainless steel raw temperatures above the threshold for stress corrosion cracking on the RHR side of water environment? The scope of the program does not include cracking as a managed the tubes. Since this heat exchanger is cooled by service water it is part of the effect. What controlled techniques will be used to manage cracking? Service Water Integrity program. In LRPD-02 section 4.20.B.1 .b the scope of this program includes the aging effect of cracking. As described in section 4.20.B.4.b under Detection of Aging Effects, heat exchanger tubes are eddy current tested to detect the presence of cracking. The RHR heat exchanger tubes identified by this line item are periodically eddy current tested which would detect the presence of cracking.

333 3.2.2-H1-09 LR Commitment 34 In Table 3.2's of the LRA, please justify the use of System Walkdown Program on LRA Amendment bolting components with loss of material aging effect. The NUREG-1 801 recommends Bolting Integrity Program please justify your position on these Section 3.2 line items. The System Walkdown Program is used to manage loss of material in bolting through the use of visual inspections that are performed at least once per refueling cycle. The GALL Bolting Integrity Program XI.M18 also credits the system walkdown program for the detection of leakage in bolted joints which could lead to loss of material but does not specify an inspection frequency. The application of the System Walkdown program to manage loss of material is therefore consistent with the GALL XI.M18 program.

In addition, a Bolting Integrity Program is in development that will address the aging management of bolting in the scope of license renewal. The Bolting Integrity Program will be implemented prior to the period of extended operation in accordance with commitment number 34.

Additional information for the Bolting Intergity Program is provided in LRA Amendments 18 and 23.

1:38:00 PMPM Page 119 of 150 11/14/2007 1111,419007 1:38:00 Page 11!9 of 150

Item Reauest Response Item RauestResDonse 334 3.3.1-37-K-01 This item concerns materials susceptible to IGSCC that would have been the Please provide documentation of the material(s) used in the RWCU system, including subject of Generic Letter 88-01. A copy of the VYNPS response to G.L. 88-01 was welds. provided for review as were drawings of the RWCU system and the Piping specification. Based on the information in the response to G.L. 88-01, none of the piping in the RWCU system is susceptible to IGSCC. Therefore, the GALL BWR Reactor Water Cleanup System Program XlM25 is not required for aging management.

VflrZ..+/-......~.. - . Page 120 of 150 1111412007 1:38:00,PM 17/14/20071:38:00 PM Page 120 of 150

Item Request Response 335 3.3.1-61-W-1 LRA Amendment In Table 3.5.2-6 on page 3.5-80 of the LRA for component Penetration sealant, material elastomer in a protected from weather environment; the aging effects are cracking and In Table 3.5.2-6 on Page 3.5-80 of the LRA, the aging effects for component change in material properties. Two AMPs are shown, Fire Protection and Structures Penetration sealant, material elastomer in a protected from weather environment are Monitoring. The referenced GALL line item is VII.G-1 and the Table 1 line item is 3.3.1- cracking and change in material properties. For clarification, this component line

61. GALL line item VII.G-1 is for component Fire barrier penetration seals. In the LRA item will be separated into two line items as follows.

on page 3.3-49 for table 1 line item 3.3.1-61-W-1 In Table 3.5.2-6 on Page 3.5-80 of the LRA, the aging effects for component There is this sentence in the discussion: Cracking and the change in material properties Penetration sealant, material elastomer in a protected from weather environment are of elastomer seals are managed by the Fire Protection Program. Explain why this AMR cracking and change in material properties. For clarification, this component line line item is not split into two lines: (1) penetration sealant (fire) with AMP Fire item will be separated into two line items as follows.

Protection, GALL reference VII.G-1, Table 1 line item 3.3.1-61 and a note B as well as (2) penetration sealant (flood, radiation) with AMP Structures Monitoring, GALL Delete line item:

reference III.A6-12, Table 1 line item 3.5.1-44 and a note C. Penetration sealant (fire, flood, radiation)

- EN, FB, FLB, PB, SNS

- Elastomer

- Protected from weather

- Cracking Change in material properties

- Fire protection Structures Monitoring

- II1.A6-12 (TP-7)

- 3.5.1-44

-C Add line items:

Penetration sealant (fire)

- EN, FB, PB, SNS

- Elastomer

- Protected from weather

- Cracking Change in material properties

- Fire Protection

- VII.G-1 (A-1 9)

- 3.3.1-61

-B Penetration sealant (flood, radiation)

- EN, FLB, PB, SNS

- Elastomer

- Protected from weather

- Cracking Change in material properties

- Structures Monitoring

- II1.A6-12 (TP-7)

- 3.5.1-44

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Item Request Response 336 3.3.1-61-W-2 LRA Amendment "In Table 3.5.2-6 on page 3.5-80 of the LRA for component Seismic isolation joint, material elastomers in a protected from weather environment; the aging effects are In Table 3.5.2-6 on page 3.5-80 of the LRA, the aging effects for component cracking and change in material properties. The AMP shown is Fire Protection. The Seismic isolation joint, material elastomers in a protected from weather environment referenced GALL line item is VII.G-1 and the Table 1 line item is 3.3.1-61. GALL line are cracking and change in material properties. The AMP shown is Fire Protection.

item VII.G-1 is for component Fire barrier penetration seals. In the LRA on page 3.3-49 The referenced GALL line item is VII.G-1 and the Table 1 line item is 3.3.1-61. The for table 1 line item 3.3.1-61 there is this sentence in the discussion: ""Cracking and the following changes will be made.

change in material properties of elastomer seals are managed by the Fire Protection Program."" There is no mention of seismic gaps. 1) Note C will be changed to Note 'E' In the LRA on page 3.5-39 for table 1 line item 3.5.1-44 there are these sentences in the discussion: ""Loss of sealing is a consequence of elastomer cracking and change in 2) The discussion in Table line Item 3.3.1-61, Page 3.3-49 will be clarified to read as material properties. Component types include: moisture barrier, compressible joints follows.

and seals used for seismic gaps, and fire barrier seals. The Structures Monitoring Program manages cracking and change in material properties."" Since this discussion "This line item was not used in the auxiliary systems tables. Fire barrier seals are talks aboutseismic gaps and fire barrier seals, explain why this AMR line item does not evaluated as structural components in Section 3.5. Cracking and change in material show Structures Monitoring as the AMP instead of Fire Protection with GALL reference properties of elastomer seals, including seismic isolation joints located in fire II1.A6-12, Table 1 line item 3.5.1-44 with note C. barriers, are managed by the Fire Protection Program."

3) An additional line item will be added to read as follows.

Seismic isolation joint

- SSR

- Elastomer

- Protected from weather

- Cracking Change in material properties

- Structures Monitoring

-III.A6-12 (TP-7)

- 3.5.1-44

-C 337 3.3.1-63-W-1 LRA Amendment In Table 3.5.2-6 on page 3.5-72 of the LRA for component Fire doors, material carbon steel in a protected from weather environment; the aging effect is loss of material. The In Table 3.5.2-6 on Page 3.5-72 of the LRA, the aging effect for component Fire referenced GALL line item is VII.G-3 and the Table 1 line item is 3.3.1-63. GALL line doors, material carbon steel in a protected from weather environment is loss of item VII.G-3 is for component Fire rated doors. Explain why the note is C, (different material.

component but consistent with GALL otherwise) for this AMR line item, instead of note 'Note C' will be changed to 'Note B' since the component matches NUREG-1801 B (Consistent with GALL, but AMP takes exceptions) and the AMP has exceptions.

PM

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Item Request .Response 338 3.3.1-71-K-01 It is understood that the line items being referred to are carbon steel components Diesel system carbon steel piping, piping components, and piping elements exposed to exposed to untreated air that credit the Periodic Surveillance and Preventive air are to be inspected for loss of material. Please provide implementing procedures Maintenance (PSPM) program. The tasks that are proposed to perform the that are used to manage this aging effect. inspections of these components currently require enhancement to include the components and perform the inspection and are not available for review, but will be created prior to the period of extended operation. However, in Attachment 3 of LRPD-02 "Aging Management Program Evaluation Results" there is a listing of the activities included in the PSPM program. The line item in this table applicable to these components is listed under AMRM-13 Credited Activities (Emergency Diesel Generator System).. This listing provides the following information about each of the activities:

- Procedure or activity to be enhanced or created,

- scope of program,

- parameters monitored or inspected,

- detection of aging effects and acceptance criteria.

339 3.2.2-Hi-10 The untreated water environment in these components is in the Drywell floor drains In Table 3.2.2-7 of the LRA, why is Containment Leak Program used to manage loss of sump and equipment drains containment penetrations and is not service water material in untreated water environment? Why is the Service Water Integrity not used to which would be called out as an environment of raw water. Therefore, the service manage these line items? water program would not be appropriate to manage this component. Since this is a containment penetration it is tested as part of the Containment Leak Rate Program which performs containment penetration leak rate testing. The testing of this penetration confirms the integrity of the penetration and provides evidence that there are no significant aging effects present that could impact the ability of the containment penetration to perform its intended function of isolating containment. In addition, the penetration will be visually inspected during the testing process while connecting test equipment to confirm the lack of significant aging effects. As documented in LRPD-02 the Containment Leak Rate Program is supplemented by the Containment Inservice Inspection Program which performs inspections of containment including the penetrations.

11/14/2007 1:38:00 PM Page 123 of 150

Item Request Response 340 3.3.2-H1 It is understood that the line items being referred to are carbon/stainless steel In the Standby Gas Treatment System the valve body and piping components in a raw components exposed to raw water that credit the Periodic Surveillance and water environment is managed by Periodic Surveillance and Preventive Maintenance Preventive Maintenance (PSPM) program. The tasks that are proposed to perform Program, what procedures and following actions are used to manage this component? the inspections of these components currently require enhancement to include the components and perform the inspection and are not available for review, but will be created prior to the period of extended operation. However, in Attachment 3 of LRPD-02 "Aging Management Program Evaluation Results" there is a listing of the activities included in the PSPM program. The line item in this table applicable to these components is listed under AMRM-07 Credited Activities (Standby Gas Treatment System).. This listing provides the following information about each of the activities:

Procedure or activity to be enhanced or created, scope of program, parameters monitored or inspected, detection of aging effects and acceptance criteria.

The demister drainage system is captured in the PSPM program when it is developed. Provided copies of the following: Dwg G-1 91238, ME-118 (PM Basis) and various photos of the Standby Gas Treatment demister drainage system to demonstrate evidence of maintenance and inspection that is performed on the demister drainage system.

341 3.3.1-72-K-01 It is understood that the line items being referred to are steel ducting and Steel HVAC and SWS system ducting and components exposed to condensation components exposed to condensation (int) that credit the Periodic Surveillance and (internal surfaces) are to be inspected. Please provide the implementing procedures Preventive Maintenance (PSPM) program. The tasks that are proposed to perform that are used to manage this aging effect. the inspections of these components currently require enhancement to perform the inspection and are not available for review but will be created prior to the period of extended operation. However, in Attachment 3 of LRPD-02 "Aging Management Program Evaluation Results" there is a listing of the activities included in the PSPM program. The line items in this table applicable to these components are listed under AMRM-19 credited activities (Heating, Ventilation and Air Conditioning System) and AMRM-1 1 credited activities (Service Water Systems) This listing provides the following information about each of the activities:

Procedure or activity to be enhanced or created, scope of program, parameters monitored or inspected, detection of aging effects and acceptance criteria.

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Item Request Response 342 3.3.2-10-W-1 LRA Amendment

[Original Question]

In Table 3.3.2-10 on page 3.3-126 of the LRA for component Duct flexible connection, [Original Response]

material fiberglass in an Air indoor (int) environment; the aging effect is none. Provide The aging effects were based on the Non-Class 1 Mechanical Implementation the technical basis justifying that fiberglass material does not have any aging effects in Guideline and Mechanical Tools, Revision 3, EPRI, Palo Alto, CA: 2001. 1003056 an indoor air environment. (The Mechanical Tools). The evaluation of aging effects for non-metallics in air is

[Follow-up Question] included in Appendix D of the Mechanical Tools. This section concludes for non-For other non-metallic components, two mechanisms Of degradation (from sustained metallics other than elastomers there are no aging effects requiring management.

vibratory loading and from wear) were considered. Please clarity the basis for concluding that these aging mechanisms are not applicable to flexible duct connections [Follow-up Question Response]

of fiberglass. Response: As shown in LRA Section 3.3 tables, the elastomer components exposed to indoor air and subject to aging management review are duct flexible connections in the heating, ventilation, and air conditioning system (LRA Table 3.3.2-10). These connections are an elastomer coated fiberglass duct fabric installed between ventilation fans and ductwork to reduce vibration and noise resulting from operation of the fans. Loss of material due to wear occurs due to the relative motion between two surfaces. Since the connections are fixed at both ends and are not in contact with other components, they have no relative motion with other components that would produce an aging effect of loss of material due to wear.

In accordance with GALL and the Structural Tools, sustained vibration loading is a mechanism that could lead to cracking of the fiberglass duct flexible connections.

Since this component has an elastomer coating, VYNPS uses the Periodic Surveillance and Preventive Maintenance Program to manage cracking as a result of sustained vibratory loads as shown in LRA Table 3.3.2-10 Line Item [Duct flexible connection" Material / "elastomer"].

LRA Section 3.3.2.2.13 Loss of Material due to Wear will be revised to state the following, Wear is the loss of surface layers due to relative motion between two surfaces. At VYNPS, in the auxiliary systems, this specific aging effect is not applicable because the heating, ventilation, and air conditioning elastomer coated fiberglass duct flexible connections are fixed at both ends, precluding wear. This item is not applicable to VYNPS auxiliary systems.

343 3.3.2-11-W-1 The aging effects were based on the Non-Class 1 Mechanical Implementation In Table 3.3.2-11 on page 3.3-135 of the LRA for component Diaphragm, material Guideline and Mechanical Tools, Revision 3, EPRI, Palo Alto, CA: 2001. 1003056 stainless steel in a silicone (ext) environment; the aging effect is none. Provide the (The Mechanical Tools). The silicone fluid used in these instrument lines is a non-technical basis justifying that stainless steel material does not have any aging effects in conductive and essentially inert fluid. The evaluation of aging effects for external a silicone environment. surfaces is included in Appendix E of the Mechanical Tools. As can be seen in Appendix E Table 4-1, "Aging Effects Summary- External Surface", there are no aging effects requiring management for external stainless steel surfaces exposed to silicone due to the inherent resistance of stainless steel to aging effects when not wetted by water or exposed to aggressive chemicals.

PM Page 125 of 150 11/14/20071:38:00 1111412007 1:38:00 PM Page 125 of 150

Item Request Response 344 3.3.2-13-40-W-1 The aging effects were based on section 2.1.8 of Appendix A in the Non-Class 1 In Table 3.3.2-13-40 on page 3.3-228 of the LRA for component Sight glass, material Mechanical Implementation Guideline and Mechanical Tools, Revision 3, EPRI, Palo glass in a Sodium pentaborate solution (int) environment; the aging effect is none. Alto, CA: 2001. 1003056 (The Mechanical Tools). This section identifies for glass Provide the technical basis justifying that glass material does not have any aging that there are no aging effects requiring management in a treated water environment effects in a sodium pentaborate solution. as long as it is not in contact with hydrofluoric acid or caustics. The sight glass in question is on the test tank in the SLC system. The Test Tank and sight glass is filled with Demineralized Water (pH - 6.0 to 7.0) during testing, and the main SLC tank sodium pentaborate solution is also an essentially neutral solution (pH of 7.03)such that the sight glass can only be exposed to a neutral solution of treated water and sodium pentaborate that will not affect the glass.

345 3.3.2-13-9-W-1 LRA Amendment In Table 3.3.2-13 on page 3.3-163 of the LRA for.component bolting, material stainless steel in an air - outdoor (ext) environment; the aging effect is none. NUREG-1833 on This is an error in the LRA for this line item. Stainless steel that is exposed to page 93 for item TP-6 provides a new MEAP for stainless steel, in an Air-outdoor outdoor air and wet/dry cycling is subject to loss of material. This correction environment with an aging effect of loss of material/pitting and crevice corrosion. In the requires an amendment to the LRA to identify loss of material as an aging effect precedent/technical basis column for this new MEAP it is stated that an approved which is managed by the system walkdown program.

precedent exists for adding this material, environment, aging effect, and program combination to the GALL Report. As shown in RNP SER Section 3.5.2.4.3.2, galvanized steel and stainless steel in an outdoor air environment could result in loss of material due to constant wetting and drying conditions. Discuss the location of the circulating water system bolting components at VYNPS and how they are protected from constant wetting and drying conditions.

346 3.3.2-6-W-1 In accordance with EPRI report 10010639 "Non Class 1 Mechanical Implementation In Table 3.3.2-6 on page 3.3-94 of the LRA for component flame arrestor, material Guideline and Mechanical Tools" aluminum is a material that is highly resistant to aluminum in an air - outdoor (ext) environment; the aging effect is none. NUREG-1833 corrosion in atmospheric environments. The outdoor air environment at VYNPS is on page 93 for item TP-6 provides a new MEAP for aluminum, in an Air-outdoor non aggressive due to its remote location from industrial facilities and salt water. As environment with an aging effect of loss of material/pitting and crevice corrosion. In the a result the amount of contaminants in the air do not provide an environment where precedent/technical basis column for this new MEAP it is stated that an approved wet/dry cycling from rain would concentrate contaminants to a sufficient degree that precedent exists for adding this material, environment, aging effect, and program would lead to loss of material in aluminum.

combination to the GALL Report. As shown in RNP SER Section 3.5.2.4.3.2, galvanized steel and stainless steel in an outdoor air environment could result in loss of material due to constant wetting and drying conditions. Aluminum would also be susceptible to a similar kind of aging effect in the outdoor environment. Discuss the location of the flame arrestor component at VYNPS and how it is protected from constant wetting and drying conditions.

347 3.3.2-6-W-2 The aging effects for fiberglass in fuel oil are based on the Non-Class 1 Mechanical In Table 3.3.2-6 on page 3.3-96 of the LRA for component Piping, material fiberglass in Implementation Guideline and Mechanical Tools, Revision 3, EPRI, Palo Alto, CA:

a Fuel oil (int) environment; the aging effect is none. Provide the technical basis 2001, 1003056 (The Mechanical Tools). Appendix C, section 2.1.6 of the guideline justifying that fiberglass material does not have any aging effects in a Fuel oil states environment.

"Therefore, based on industry operating experience review and the assumption of proper design and application of the material, aging of glass (including fiberglass) and thermoplastics in lubrication and fuel oil environments is not an applicable aging effect."

PM Page 126 of 150 11 III 4/2007 1:38:00 8:00 PM Page 126 of 150

Item - Request Response 348 3.3.2-6-W-3 The interstitial fluid (brine) environment is colored treated water with antifreeze In Table 3.3.2-6 on page 3.3-97 of the LRA for component Tank, material fiberglass in located between the inner and outer walls of a double-walled fiberglass fuel oil tank an Interstitial fluid (brine) (int) environment; the aging effect is none. Provide the and can be considered a treated water environment due to its benign effects on technical basis justifying that fiberglass material does not have any aging effects in a materials. The fluid is used for leak detection and is provided by the manufacturer Interstitial fluid (brine) environment. of the tank. The aging effects for fiberglass in interstitial fluid are based on Section 2.1.8 of the Non-Class 1 Mechanical Implementation Guideline and Mechanical Tools, Revision 3, EPRI, Palo Alto, CA: 2001, 1003056 (The Mechanical Tools) which states:

"Therefore, based on industry operating experience review and the assumption of proper design and application of the material, aging of glass and thermoplastics in treated water environments is not an applicable aging effect."

349 3.3.2-6-W-4 Duplicate of #348.

In Table 3.3.2-6 on page 3.3-97 of the LRA for component Tank, material fiberglass in an Interstitial fluid (brine) (int) environment; the aging effect is none. Provide the technical basis justifying that fiberglass material does not have any aging effects in a Interstitial fluid (brine) environment.

1 1 1 120 7 P

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1111412007 1:38:00 PM Page 127 of 150

Item Request Response Item Request ResDonse 350 B.1.27.3-E-01 LRA Amendment Please clarify the FERC provisions under which the Vernon Dam is inspected. The dam is now exempt from Provisions of Title 18, Part 12, Subpart D, (Inspection by The Vernon Dam is inspected in accordance with the Provisions of Title 18 Parts 8 Independent Consultant). and 12. The LRA Appendix A Item A.2.1.31 states that, subpart D (inspection by Independent Consultant) is applicable, however an exemption from this requirement for an independent consultant review has been received and this secondary review is no longer performed.

This will require the following:

1) LRPD-02 Section 4.21.3.B. "Program Description" will be revised to read; The Vernon dam is subject to the Federal Energy Regulatory Commission (FERC) inspection program. This program consists of visual inspections in accordance with FERC guidelines and is in compliance with Title 18 of the Code of Federal Regulations, Conservation of Power and Water Resources, Part 12 (Safety of Water Power Projects and Project Works) and Division of Dam Safety and Inspections Operating Manual. The operation inspection frequency for licensed and exempt low hazard potential dams is biennially. NRC has found that mandated FERC inspection programs are acceptable for aging management.

LRPD-02 Section 4.21.3.C- "Summary" will be revised to read:

The Vemon Dam FERC Inspection (performed biennially) has been effective at managing aging effects..."

2) LRA Section A.2.1.31 Structures Monitoring-Vernon Dam FERC Program will be revised to read:

The Vernon dam is subject to the Federal Energy Regulatory Commission (FERC) inspection program. This program consists of visual inspections in accordance with FERC guidelines and is in compliance with Title 18 of the Code of Federal Regulations, Conservation of Power and Water Resources, Part 12 (Safety of Water Power Projects and Project Works) and Division of Dam Safety and Inspections Operating Manual. The operation inspection frequency for licensed and exempt low hazard potential dams is biennially. As indicated in NUREG-1 801 for water control structures, NRC has found that FERC / US Army Corp of Engineers dam inspections and maintenance programs are acceptable for aging management.

351 B.1.27.3-E-02 RAI 3.6.2.2.N-08 Please provide copies of Vernon Dam biennial FERC Inspection Reports issued since 6/24/2002. The requested inspection reports are not readily available for security reasons. After September 11, 2001, access to Vernon Dam inspection reports has been restricted.

Entergy VY has worked with the Vermont's Department of Public Service legal staff and-has located these reports (e.g. Vermont required access to these reports for the sale of Vernon Dam to TransCanada). Sarah Hofmann, Esquire and Director for Public Advocacy, Department of Public Service in Montpelier, VT (Phone # = 802-828-3088), can be contacted to view this information.

.... 1:38:00-1 /1 4/2007 .. PM ..... **L * . *}*

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. 128 1111412007 1:38:00 PM Page 128 of 150

Item Request Response 352 Are the VY fatigue analyses of record based on design rates of change of temperature, 352 Are the VY fatigue analyses of record based on design rates of change of temperature, RAI 4.3-H-03 or on actual plant limits?

The existing VY fatigue analyses are done based on design rates of change of How will future analyses be done? temperature.

Follow on Question 6/26: Have there been transients in which the actual rates of Future fatigue analyses will be based on design rates of change or on actual plant change in temperature exceed the rates of change used in the design analysis? operating limits, if required.

Follow on Question Response:

A review of early plant vessel thermal cycle experience is contained in calculation VYC-378 Rev.1 (at Attachment 1 page 56 of 131). Table 4 documents heatup-cooldown cycles from plant startup in 1972 thru 4/80. The table documents 7 cooldown events and 2 heatups occurring from 1972 through 1974 where the rate of temperature change exceeds-100F per hour. However, each of these events applies to a limited time (typically 0.1 hours1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months ) and only over a limited temperature range within the heatup or cooldown event. The maximum temperature change of 120F vs. the full temperature range of 446F (1OOF to 546F).

Theses events occurred in the early years of operation, with operating experience, Table 4 shows only one heatup in which the rate of temperature change exceed 100F.

This was a scram on 2/3/78 where the rate of change is documented as 120F/hr.

This was noted as non-typical due to loss of Vital AC.

353 Provide a copy of SIR-01 -301 showing the system design transients for VY. A copy of SIR-01 -301 has been provided.

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Item Request Response 354 Do the analyses for internals (Section 4.7.2) include all system transients? LRA Amendment Do the CUF values calculated in the BWRVIPs really apply to VY? If not, should these The TLAA discussed in Section 4.7.2.3 (Shroud Support) and Section 4.7.2.4 analyses be considered TLAA? (Lower Plenum) are VYNPS specific calculations that are included in Table 4.3-1 of the LRA. These analyses are based on the VYNPS design system transients.

The analyses in Section 4.7.2.5 (Vessel ID attachment welds) and Section 4.7.2.6 (Instrument penetrations) are generic analyses performed in the BWRVIP documents. These are not VYNPS specific calculations. As such, these are not TLAA for VY.

This requires an amendment to the LRA to delete Section 4.7.2.5 delete Section 4.7.2.6.

delete vessel ID attachment welds and instrument penetrations from LRA Table 4.1-10 delete the cracking-fatigue with TLAA-metal fatigue from the internals attachments entry in LRA table 3.1.2-1 (page 3.1-54) Note cracking managed by the BWR Vessel ID Attachment Welds Program remains in the table.

delete the cracking-fatigue with TLAA-metal fatigue from the nozzles, instrumentation, N11 and N12 in LRA table 3.1.2-1 (page 3.1-44). Note that cracking managed by the BWR Penetrations Program remains in the table.

delete Section A.2.2.7 delete Section A.2.2.8 No changes to 'App. B' or 'App. C'

/ 355 GE report 26A6019 states that some components have fatigue analyses done to later Provided copy of PUSAR Chapter 3.2 which lists the RR nozzle safe ends and code versions than 1965. What are those components and code versions? instrumentation nozzle safe ends and the code year used for each. They were done to the 1982 version of ASME Section III.

356 GE report 26A6019 references ASME Section XI, 1986. Where did VY invoke this Provided copy of PUSAR Chapter 3.2 which shows that the core spray safe ends code? repair was performed using ASME Section XI, 1986.

357 The PUSAR (Table 3-3 of NEDC-33090P) shows no changes to the stresses of As discussed in Section 3.2.2.2 of NEDC-33090P, the original stress evaluations components other than the FW nozzles. Why is this correct when temperature and were performed at conditions that bound the slight change in operating conditions changed 0.6%. for the CPPU. Only the feedwater nozzle had enough of a change in parameters to need a re-calculation of CUF.

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Item Request Response 358 Please provide a description or a reference to the "augmented" class 2/3 fatigue For the Torus attached piping plant-specific fatigue analyses are performed for each methodology that was developed to account for cycle mechanical loads, penetration.

The calculation for the SRV vent pipe penetrations is Teledyne Engineering Services (TES) Calculation No. 5319-28, Rev.0 "SRV Vent Pipe Penetration Stress Evaluation Vermont Yankee SRV Lines A - D". The penetration analysis is performed using a finite element model of the penetration and vent pipe. Loads are taken from the attached piping model. Stress intensities and secondary stress ranges are calculated and compared with ASME allowables. The fatigue evaluation is shown on page 65. Stress concentrations from WRC Bulletin 107 are used. The maximum usage factor calculated is 0.49 for 10,000 cycles.

For torus attached piping, the calculations include an ASME stress evaluation of the torus nozzle. A local WRC Bulletin 107 type nozzle analysis is performed and the results are combined with free shell stresses from a finite element model of the torus shell. Loads are taken from the attached piping model. Stress intensities and secondary stress ranges are calculated and compared with allowables. Stress concentrations from WRC Bulletin 107 are used.

A typical torus nozzle calculation is (TES) Calculation No. 5319-X227, Rev.0 "Torus Attached Piping -X227". The fatigue evaluation is shown on page 42. The maximum usage factor calculated is 0.33 for 10,000 cycles.

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Item Request Response Item Request ResDonse 359 3.4.2-M-04 LRA Amendment Currently, in VYNPS LRA Section 3.4.2.1, the applicant identified the following programs that manage the aging effects related to the main condenser and MSIV As stated in LRA Section B.1.30.2, the Water Chemistry Control - BWR Program is leakage pathway components and component groups; 1) Flow-Accelerated Corrosion, consistent with the program described in NUREG-1 801,Section XI.M2, 'Water

2) System Walk-Down, 3) Water Chemistry Control-BWR, and 4) Water Chemistry Chemistry." The One-Time Inspection Program, described in LRA Section B.1.21 Control-Closed Cooling Water. Will the One-Time Inspection program be added to this -includes inspections to verify the effectiveness of the water chemistry control aging listing? management programs (Water Chemistry Control - Auxiliary Systems, Water Chemistry Control - BWR, and Water Chemistry Control - Closed Cooling Water) by confirming that unacceptable cracking, loss of material, and fouling is not occurring. As stated in LRA Section B.1.21, the One-Time Inspection Program is a new program which will be consistent with the program described in NUREG-1 801,Section XI.M32, "One-Time Inspection."

LRA Tables 3.1.1, 3.2.1, 3.3.1, and 3.4.1 indicate that the One-Time Inspection Program is credited along with the water chemistry control programs for line items for which GALL recommends a one-time inspection to confirm water chemistry control. For simplicity, the subsequent tables (Table 2's) do not list the One-Time Inspection Program each time a water chemistry control program is listed. However, since the One-Time Inspection Program is applicable to each water chemistry control program, it is also applicable to each line item that credits a water chemistry control program.

To provide further clarification, the effectiveness of the Water Chemistry Control -

Auxiliary Systems, BWR, and Closed Cooling Water programs is confirmed by the One-Time Inspection program. This requires an amendment to the license renewal application to change the Appendix A, SAR supplement descriptions for the Water Chemistry Control -Auxiliary Systems, BWR and Closed Cooling Water programs to explicitly state One-Time Inspection Program activities will confirm the effectiveness of these programs.

360 3.4.2-M-05 No, there have been no changes in the scope of equipment subject to aging In Section 3.4.2.2.2 of the LRA, the applicant stated that, "...there are no tanks or steel management review since the scoping and screening results presented in the heat exchanger components included in the steam and power conversion systems." application were approved. No plant changes have been implemented that would They also stated that, "...the condenser is included as part of the main condenser and affect the intended functions for license renewal. The statements in Section MSIV leakage pathway but has no aging effects requiring aging management since 3.4.2.2.2 of the application remain valid. There are no steel or stainless steel tanks their intended function is for holdup & plate-out of radioactive materials. Have any exposed to treated water with intended functions in the steam and power conversion changes occurred since initial scoping that would change the above statement. systems. The intended function of main condenser and MSIV leakage pathway components, for post-accident holdup and plate-out of MSIV leakage is continuously assured by normal plant operation and cannot be affected by aging effects.

361 3.4.2-M-06 No, there have been no changes in the scope of equipment subject to aging In Section 3.4.2.2.2.2, of the LRA, the applicant stated that (in reference to the steam management review since the scoping and screening results presented in the and power conversion systems at VYNPS) "...they have no carbon steel components application was approved. No plant changes have been implemented that would requiring aging management which are exposed to lubricating oil." Therefore, they affect the intended functions for license renewal. The statement in Section further state that "...this specific item is not applicable to VYNPS. Have any changes 3.4.2.2.2.2 of the application remains valid. There are no steel components occurred since initial scoping that would change the above statement. exposed to lubricating oil with intended functions in the steam and power conversion systems.

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Item Reauest Resoonse 362 3.4.2-M-07 No, there have been no changes in the scope of equipment subject to aging The applicant stated, in Section 3.4.2.2.3of the LRA, that "...for loss of material due to management review since the scoping and screening results presented in the general, pitting, crevice, MIC, and fouling - which could occur in steel piping, piping application were approved. No plant changes have been implemented that would components, and piping elements exposed to raw water - in the steam and power affect the intended functions for license renewal. The statement in Section 3.4.2.2.3 conversion systems at VYNPS; they have no carbon steel components requiring aging of the application remains valid. There are no steel components exposed to raw management which are exposed to raw water." Therefore, they further state that "...this water with intended functions in the steam and power conversion systems.

item is not applicable to VYNPS. Have any changes occurred since initial scoping that would change the above statement.

363 3.4.2-M-08 No, there have been no changes in the scope of equipment subject to aging The applicant stated, in Section 3.4.2.2.5.1 of the LRA, that "...for the loss of material management review since the scoping and screening results presented in the due to general, pitting, crevice, and MIC - which could occur in carbon steel (with or application were approved. No plant changes have been implemented that would without coating or wrapping) piping, piping components, piping elements and tanks affect the intended functions for license renewal. The statement in Section exposed to soil - in the steam and power conversion systems at VYNPS; they have no 3.4.2.2.5.1 of the application remains valid. There are no steel components with carbon steel components requiring aging management that are exposed to soil." intended functions exposed to soil in the steam and power conversion systems.

Therefore, they further state that "...this item is not applicable to VYNPS. Have any changes occurred since initial scoping that would change the above statement.

364 3.4.2-M-09 No, there have been no changes in the scope of equipment subject to aging The applicant stated, in Section 3.4.2.2.7.2 of the LRA, that "...for the loss of material management review since the scoping and screening results presented in the due to pitting and crevice corrosion - which could occur in stainless steel piping, piping application were approved. No plant changes have been implemented that would components, and piping elements exposed to soil - in the steam & power conversion affect the intended functions for license renewal. The statement in Section systems at VYNPS; they have no stainless steel components requiring aging 3.4.2.2.7.2 of the application remains valid. There are no stainless steel management that are exposed to soil." Therefore, they further state that "...this item is components exposed to soil with intended functions in the steam and power.

not applicable to VYNPS. Have any changes occurred since initial scoping that would conversion systems.

change the above statement. Have any changes occurred since initial scoping that would change the above statement.

365 3.2.2-H1-12 See response to Question 309.

In Section 3.2 of the LRA, there are numerous line items in Table 3.2's with TLAA-metal fatigue as the Aging Management Program. Can you provide the staff with the TLAA Close item to item #309.

analysis for each line item?

366 3.4.1 -M-04 The discussion column entry for item 3.4.1-23 states, "Not applicable. There are no Currently, in VYNPS LRA Table 3.4.1, Item 3.4.1-23 discussion column, the applicant stainless steel components exposed to closed cycle cooling water in the steam and states, "...the cracking of stainless steel piping, piping components, and piping power conversion systems." This statement is meant to imply that within the steam elements exposed to closed cycle cooling water >60 C (>140 F) due to SCC is not and power conversion systems, there are no components with an intended function applicable at VYNPS." In light of statements presented in GALL VIII.E-25 (for the for license renewal that are made of this material and exposed to this environment.

Condensate System), further explain how this "MEA" combination is not applicable to This may be confirmed by an inspection of Table 3.4.2-1. While there may be such VYNPS. components in systems that are included in the scope of license renewal, these components have been screened out because they are not needed to complete the license renewal intended functions.

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Item Request Response 367 3.4.1 -M-05 The discussion column entry for item 3.4.1-35 states, "Not applicable. There are no Currently, in VYNPS LRA Table 3.4.1, Item 3.4.1-35 discussion column, the applicant copper alloy components subject to selective leaching in the steam and power states, "...the loss of material of copper alloy >15% Zn piping, piping components, and conversion systems." The only components within the steam and power conversion piping elements exposed to closed cycle cooling water, raw water, or treated water due systems with an intended function for license renewal that are composed of copper to selective leaching is not applicable at VYNPS." In light of statements presented in with >15% zinc, are the condenser tubes. As identified in plant specific note 401, GALL VIII.E-20 (for the Condensate System - Main Condenser Outside Tube Side), the intended function of condenser components is for post-accident holdup and further explain how this "MEA" combination is not applicable to VYNPS. plate-out of MSIV leakage. This function is continuously assured by normal plant operation and cannot be affected by selective leaching of the tubes. Thus, this aging effect does not require management and is not included in Table 3.5.2-1.

368 3.4.1-M-06 The discussion column entry for item 3.4.1-23 states, "Not applicable. There are no Currently, In VYNPS LRA Table 3.4.1, Item 3.4.1-36 discussion column, the applicant gray cast iron components exposed to raw water with intended functions in the states, "...the loss of material of gray cast iron piping, piping components, and piping steam and power conversion systems." This statement is meant to imply that within elements exposed to soil, treated water, or raw water due to selective leaching is not the steam and power conversion systems, there are no components with an applicable at VYNPS." In light of statements presented in GALL VIII.E-22 (for the intended function for license renewal that are made of this material and exposed to Condensate System - Main Condenser Piping), further explain how this "MEA" this environment. This may be confirmed by an inspection of Table 3.4.2-1. While combination is not applicable to VYNPS. there may be such components in systems that are included in the scope of license renewal, these components have been screened out because they are not needed to complete the license renewal intended functions.

369 3.2.2-H1-13 LRA Amendment On page 3.2-49 why is cracking being managed by Oil Analysis Program, when the program does not have a performance testing program to verify the effectiveness of the As stated in LRA Table 3.2.2-4 stainless steel components in the HPCI system at program. VYNPS that are exposed to lubricating oil are managed by the Oil Analysis Program, which includes periodic sampling and analysis of lubricating oil to maintain the presence of water within acceptable limits, thereby preserving an environment that is not conducive to cracking. As stated in LRA Section B.1.20, the Oil Analysis Program is consistent with the program described in NUREG-1801,Section XI.M39, Lubricating Oil Analysis, with a minor exception.

The Oil Analysis Program is not consistent with GALL XI.M32, "One-Time Inspection," nor are one-time inspections necessary to verify the effectiveness of the program. Cracking in lube oil systems can only occur with the presence of water.

Therefore, an effective oil analysis program, which maintains the amount of water at levels that are not conducive to cracking, precludes the need for one-time inspections. Operating experience at VYNPS has confirmed the effectiveness of the Oil Analysis Program in maintaining moisture and impurities within limits such that cracking has not and will not occur and affect the intended functions of these components.

In numerous past precedents (including NUREG-1 828, Arkansas Nuclear One Unit 2 SER, Section 3.0.3.3;6, and NUREG-1 831, Donald C. Cook SER, Section 3.0.3.3.8), the staff concluded that an effective oil analysis program, which maintains impurities and moisture below specified limits, is sufficient to demonstrate that the effects of aging will be adequately managed so that the intended functions will be maintained consistent with the current licensing basis for the period of extended operation.

The One-Time Inspection program will be revised to include activities to confirm the effectiveness of the Oil Analysis and Diesel Fuel Monitoring programs.

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Item Request Response 370 3.2.2-H1-14 The component in question is a steam heater in the RCIC system. The entry says On Table 3.2.2-5 page 3.2-66, can you provide justification why cracking-fatigue aging cracking-fatigue is an aging effect requiring management and it is managed by the effect does not have a TLAA-metal fatigue, Aging Management Program? Heat Exchanger Monitoring program.

As suggested in questions 309 and 365, a metal fatigue TLAA is not automatically associated with every component exceeding the temperature threshold for cracking-fatigue. TLAA-metal fatigue is the appropriate entry only if there is in fact a TLAA (fatigue analysis) for the component in question. In this case there is no fatigue analysis and an AMP was specified that manages cracking-fatigue.

371 In the Table 4.3-2 of VT LRA, the design basis cycles for Design Transient 6 (Reactor LRA Amendment startup/shutdown cycles) has to be determined based on the design analysis. Please RAI 4.3-H-01 provide LRA supplement to address this issue The LRA will be amended to include the following discussion of the VYNPS transient monitoring program.

The VYNPS Fatigue Monitoring Program includes counting of the cycles incurred by the plant. Five transients are monitored by plant operations and recorded as they occur. It is projected that less than 60% of the design cycles for these five transients will be used through the first 60 years of operation, including the PEO.

The remaining transients are monitored by plant engineering based on review of operating data at the end of each fuel cycle. These remaining transients are summarized in the Fatigue Monitoring Program as the sixth transient (Reactor Startups and Shutdowns). Engineering evaluates these transients and advises operations if the number of design cycles is being approached.

RAI Response 4.3-H-01 provided in VYNPS Letter to NRC BVY 07-003.

372 3.3.1-22-K-01 RAI 3.3.1-22-K-01 Please confirm that no auxiliary components have elastomer linings or SS cladding-or if there are such components, provide additional justification for the determination that As stated in LRA section 3.3.2.2.10, stainless steel cladding or elastomer linings are pitting and crevice corrosion do not require aging management. conservatively not credited to prevent loss of material of underlying carbon steel material in auxiliary systems and as such are not identified or known. Pitting and crevice corrosion are aging effects requiring management for the carbon steel auxiliary components exposed to treated water and are managed by the water chemistry control program.

RAI 3.3.1-22-K-01 provided in VYNPS Letter to NRC BVY 06-083.

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Item Request Response 373 3.3.1-34-K-01 LRA Amendment Please identify the plant-specific program that will be used to manage loss of material due to wear. It is not clear to the project team that operating experience provides a As shown in LRA Section 3.3 tables, the elastomer components exposed to indoor sufficient basis for determining that this aging mechanism is not applicable at VYNPS. air and subject to aging management review are duct flexible connections in the heating, ventilation, and air conditioning system (LRA Table 3.3.2-10). These connections are an elastomer coated fiberglass duct fabric installed between ventilation fans and ductwork to reduce vibration and noise resulting from operation of the fans. Loss of material due to wear occurs due to the relative motion between two surfaces. Since the connections are fixed at both ends and are not in contact with other components, they have no relative motion with other components that would produce an aging effect of loss of material due to wear.

LRA Section 3.3.2.2.13 Loss of Material due to Wear will be revised to state, Wear is the removal of surface layers due to relative motion between two surfaces.

At VYNPS, in the auxiliary systems, this specific aging effect is not applicable because the heating, ventilation, and air conditioning elastomer coated fiberglass duct flexible connections are fixed at both ends, precluding wear. This item is not applicable to VYNPS auxiliary systems.

374 3.3.1-50-K-02 This error was previously noted and clarification supplied in the response to Audit Table 1 states that "[f]or stainless steel components of the demineralized water system, item 165 (see below).

the Water Chemistry Control - Auxiliary Systems program manages loss of material." To clarity, Items 3.3.1-50 and 3.3.1-51 in LRA Table 3.3.1, the Water Chemistry No items in 3.3.2-13-12 were found that credited this AMP. Please clarify. Control - BWR Program (not the auxiliary systems) is credited for managing the effects of aging on the demineralized water system as indicated in LRA Table 3.3.2-13-12, Demineralized Water (DW) System Nonsafety-Related Components Affecting.

Safety-Related Systems Summary of Aging Management Evaluation.

375 3.3.1-51-K-02 This error was previously noted and clarification supplied in the response to Audit Table 1 states that "[flor copper alloy components of the.. demineralized water item 165 (see below).

system... the Water Chemistry Control-Auxiliary Systems program manages loss of To clarify Items 3.3.1-50 and 3.3.1-51 in LRA Table 3.3.1, the Water Chemistry material." No items in 3.3.2-13-12 were found that credited this AMP. Please clarify. Control - BWR Program (not the auxiliary systems) is credited for managing the effects of aging on the demineralized water system as indicated in LRA Table 3.3.2-13-12, Demineralized Water (DW) System Nonsafety-Related Components Affecting Safety-Related Systems Summary of Aging Management Evaluation.

376 3.3.1-69-K-02 LRA Amendment In the discussion section of VYNPS LRA Table 3.3.1 item 3.3.1-69, the applicant stated that the loss of material in stainless steel components exposed to raw water is Reference to One-Time Inspection will be removed from the discussion column in managed by the Fire Water System, Fire Protection, and One-Time Inspection table 3.3.1 item 69.

Programs. During the audit and review, the project team noted that the applicant did not apply the One-Time Inspection Program to any AMR line items to which Table 3.3.1 item 3.3.1-69 was applied. Please clarity.

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Item Request Response 377 3.3.1-73-K-01 LR Commitments 17 and 20 Please confirm that aging management of steel crane structural girders in load handling will conform to the standards cited in GALL XI.M23. Reactor building steel crane structural girders used in load handling are inspected under the Periodic Surveillance and Preventive Maintenance Program (PSPM) identified in Appendix B of the application. Process facility crane rails and girders are inspected under the Structures Monitoring Program as identified in Appendix B.

The Structures Monitoring Program will be enhanced, as identified in App B, to address crane rails and girders. Aging management activities for crane rails and girders under these two programs are consistent with the attributes described for the program in GALL XI.M23. Reference commitments 17 & 20.

378 3.3.1-74-K-01 Please see Response to # 377.

Please confirm that aging management of steel crane rails will conform to the standards cited in GALL XI.M23. Reference commitments 17 & 20.

379 3.5.1-16-W-2 LRA Amendment In the accepted response to question 3.5.1-16-W-1 the applicant stated: Table 3.5.1 line Item 3.5.1-16 will be updated to read: "the aging effects cited in the NUREG-1801 Table 3.5.2-6 line item "Seals and gaskets..." on page 3.5-80 is for Class I structure item are loss of sealing and leakage. Loss of sealing is a consequence of the aging seals and gaskets not associated with primary containment boundary. Containment effects cracking and change in material properties. For VYNPS, the Containment Leak seals and gaskets are addressed in Table 3.5.2-1 Line item "Primary containment Rate Program manages cracking and change in material properties for the primary electrical penetration..." on page 3.5-55.

containment seals and gaskets. The Inservice Inspection-IWE manages cracking and change in material properties for the primary containment moisture barrier." For clarity, the following discussion will be added to Table 3.5.1-16.

In Table 3.5.2-6 (Bulk Commodities) on Page 3.5-80 of the LRA, for component seals and gaskets (doors, man-ways and hatches), material rubber in a protected from "For reactor building seals and gaskets, the Periodic Surveillance and Preventive weather environment; the aging effects are cracking and change in material properties. Maintenance Program manages cracking and change in material properties for the The GALL line item referenced is I1.B4-7 and the Table 1 reference is 3.5.1-16. railroad inner and outer lock doors elastomer seals."

However, the AMP shown for this line item is Periodic Surveillance and Preventive Maintenance. Table 3.5.1 line item 3.5.1-16 relates to primary containment seals and See also response to Item 243.

gaskets. The applicant has stated above in the previous paragraph that the Containment Leak Rate Program manages cracking and change in material properties for the primary containment seals and gaskets. The applicant is asked to explain if this table 2 line item is for containment seals and gaskets and also Class I structures seals and gaskets. If it is for both containment seals and gaskets and Class I structures seals and gaskets, the applicant is asked to explain why the line is not broken into two AMPs, two GALL items, two table 1 items and two notes. The AMP for the containment seals and gaskets would be Containment Leak Rate Program with the GALL item I1.B4-7, the Table 1 Item 3.5.1-16 and a note A. The AMP for the Class 1 structures seals and gaskets would probably be the Periodic Surveillance and Preventive Maintenance Program.

380 3.5.1-53-W-1 RAI 3.5.1-53-W-1 In Table 3.5.2-1 (Primary Containment) on Page 3.5-54 of the LRA, for component vent header support, material carbon steel in an exposed to fluid environment; the aging GALL line item 1Il..1.1-11 (treated water environment), material-stainless steel; effect is loss of material. The GALL line item shown is Ill.B1.1-13 and the Table 1 steel was considered a submerged environment. Since the VYNPS component is reference is 3.5.1-53. The AMP shown for this line item is Inservice Inspection-IWF. carbon steel in an air-moist environment, (it is not actually submerged in the fluid GALL line item 111.B1.1-13 is for an indoor uncontrolled air or outdoor air environment. environment), GALL line item 111.B1.1-13 was considered a better fit for this The applicant is asked to explain why GALL line item 111.B1.1-11 (treated water component.

environment) and Table 1 reference 3.5.1-49 are not associated with this AMR line item RAI 3.5.1-53-W-1 response provided in VYNPS Letter to NRC BVY-06-083.

and the VYNPS Water Chemistry Control - BWR Program also shown with the Inservice Inspection-IWF AMP.

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Item Request Response 381 B.1.30.1-M-04 As stated in Section 4.20 of LRPD-02, the Service Water Integrity Program, in Clarify commitment to performance monitoring/testing of HX (fouling) and pumps (LoM) accordance with NRC GL 89-13, includes condition and performance monitoring managed using OCCW (SWI) and CCCW (WCC-Aux & WCC-CCW) AMPs. activities. As these activities are already part of the existing program, a separate commitment is not necessary.

As stated in the LRA and prior RAI responses, the Water Chemistry Control -

Auxiliary Systems and Water Chemistry Control - Closed Cooling Water programs do not include performance or functional testing of heat exchangers or pumps. The programs are preventive programs which maintain the water chemistry within specified limits to minimize loss of material, cracking and fouling. Also, as described in LRA Section B.1.21, the One-Time Inspection program will verify the effectiveness of the water chemistry control aging management programs by confirming that unacceptable cracking, loss of material, and fouling is not occurring.

Therefore, the passive intended functions of pumps, heat exchangers, and other components will be adequately managed without condition or performance monitoring. [Condition and performance testing of heat exchangers and pumps is performed under the Maintenance Rule 10CFR50.65, but is not considered part of these aging management programs.]

382 Original Question: Gall AMPs X1.E1, X1.E2, X1.E3, AND X1 .E4 indicate that aging LRA Amendment effects of cables and connections and metal enclosed bus may exist. In the LRA, you have stated that there is no operating experience. Provide industrial and plant specific The programs will be updated to include the following:

operating experience for each VY AMP associated and consistent with X1 .E1, Xl .E2, X1 .E3 and Xl .E4. Confirm that the review of plant specific operating experience did not The XXX program is a new aging management program. Industry operating reveal any degradation not bound by industry experience. experience that forms the basis for the program is described in the operating experience element of the NUREG-1801 program description. VYNPS plant-specific operating experience has been reviewed against the industry operating experience identified in GALL Although VYNPS has not experienced all of the aging effects listed in GALL, the VYNPS program will manage all of the aging effects identified in the Operating Experience section of GALL.

The program is based on the program description in NUREG-1801, which in turn is based on relevant industry operating experience. As such, this program will provide

.reasonable assurance that effects of aging will be managed such that applicable components will continue to perform their intended functions consistent with the current licensing basis for the period of extended operation. As additional operating experience is obtained, lessons learned can be used to adjust the program, as needed.

383 Please identify the design code and the number of operating cycles for the MSIVs. The main steam isolation valves are built to the ASME Code for Pumps and Valves for Nuclear Power, November 1968 Draft and March 1969 addendum, issued for trial use and comment. (main steam design basis document)

Based on a review of plant operating records, VYNPS has estimated 587 operations of the main steam line isolation valves in 35 years of operation. Extrapolating this number to 60 years of operation (considering changes in surveillance testing of the valves) gives 785 cycles. This is only 38% of the design 2050 cycles for these valves.

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Item Request Response 384 Vermont Yankee intends to use the System Walkdown Program to inspect external LR Commitment 35 surfaces of components subject to aging management review. Also, the program is credited with managing loss of material from internal surfaces, for situations is which The NRC was provided with the System Walkdown Qualification List on 06/26/06.

internal and external material and environment combinations are the same such that A common Entergy activity qualification ENN-TK-ESPG-033 covers the System external surface condition is representative of internal surface condition. (LRA page B- Walkdown process and VY has provided training to System Engineering personnel 88). You have stated that Vermont Yankee System Engineers whom will perform the during cyclic training on use of the EPRI Aging Assessment Field Guide. The activity walkdowns have received training in the EPRI Aging Management Field Guide. Please code for that item is VLP-ESP-AGE-FG. The EPRI Guide has been provided to provide proof of qualification and certification of system walkdown training. System Engineers, and others as requested. Personnel receiving the guide have

1) How frequently do the engineers receive re-qualification and recertification? acknowledged receipt on a sign-off form.

2) How often do the engineers perform system walkdowns to verity their ability to 1) Q: How frequently do the engineers receive re-qualification and recertification?

provide accurate results? A: Re-qualification/recertification is rooted in the SAT process that VYNPS employs to ensure that the training provided for a particular activity results in expected performance. Programs and processes are periodically monitored through the EN-LI-i 04; "Self Assessment and Benchmark Process" and the EN-TQ-201; "Systematic Approach to Training Process", to identify personnel performance strengths and weaknesses. When weaknesses are identified through those ongoing processes, either the Corrective Action Process or the TEAR (Training Request) process is used to identify and provide solutions for performance problems. If training is identified as a solution when performance problems exist, the appropriate training course of action is identified and implemented and then evaluated for success. Currently, periodic refresher training and re-qualification is not a scheduled event because VYNPS has no data to suggest that performance shortfalls exist.

2) Q: How often do the engineers perform system walkdowns to verify their ability to provide accurate results?

A: System Engineers are required to perform a minimum of one system walkdown per month for systems that are accessible with the plant on-line. Many more detailed inspections are performed during outage periods. System Engineering Supervisors are required to observe a minimum of two system walkdowns per quarter.

Commitment Number 35 has been created to "Enhance the System Walkdown Training Program as appropriate to document biennial refresher training of Engineers to demonstrate inclusion of the methodology for aging management of plant equipment as described in EPRI Aging Assessment Field Guide or comparable instructional guide."

385 At the time Entergy performed its revised environmentally-assisted fatigue analysis, LR Commitment 27 Entergy used hydrogen water chemistry (HWC) implementation to establish the oxygen concentrations (in ppm) used in its Fen adjustment factor calculations. Clarify whether For the license renewal application, environmentally assisted fatigue factors (Fens)

Entergy factored in the oxygen concentrations derived from implementation of normal were estimated based on hydrogen water chemistry (HWC) oxygen concentration.

water chemistry (NWC) in the FEN calculations for those operational periods when Prior to the period of extended operation, VYNPS will perform fatigue analyses and NWC was being implemented instead of HWC. appropriate Fens will be used, accounting for operating times with both hydrogen water chemistry and normal water chemistry.

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Item Request ResDonse 386 B.1.22-R-01 The five year Periodic Surveillance and Preventive Maintenance (PSPM) frequency is acceptable because:

LRPD-02, "Aging Management Program Evaluation Results," states that nonsafety-related systems and components affecting safety-relates systems within the circulating (1) From our VYNPS Service Water Monitoring Program, we have learned the water system have an inspection interval of 5 years. The applicant is asked to explain following.

and justify why the inspection interval of 5 years is adequate for general corrosion of -Aerobic bacterial attack on carbon steel causes tuberculation that is only a problem carbon steel components exposed to raw water environment in the circulating water in plugging small bore piping. For circulating water, this is not a problem since all system. carbon steel pipe is large bore.

-Anaerobic bacterial attack occurs at heat-affected zones in welding. Corrosion damage typically takes 15 to 20 years to develop, and has resulted in only localized effects. The whole piping system has retained its structural integrity.

-The above bacteria are significantly inhibited when exposed to chlorination.

Circulating water is periodically treated with chlorine, which further reduces this potential for attack for this system.

-General corrosion, even in raw water systems such as circulating water, is not fast acting.

(2) PSPM inspection activities are performed on (a)(2) systems that have been in service for the life of the plant without required inspections per the VYNPS corrective action program. If significant changes are noted, the frequency in the PSPM can be updated; and (3)The consequences of failure due to loss of material are low.

(4) With the exception of the alternate cooling tower cell, the circulating water system does not run through the reactor building or near any safety related equipment. Based on the aging stressors described above, the alternate cooling tower cell will not be impacted.

SRP Appendix A, Section A.1.2.2 states that risk significance may be considered in developing the details of an aging management program (see excerpt below).

"The risk significance of a structure or component could be considered in evaluating the robustness of an aging management program. Probabilistic arguments may be used to assist in developing an approach for aging management adequacy.

However, use of probabilistic arguments alone is not an acceptable basis for concluding that, for those structures and components subject to an AMR, the effects of aging will be adequately managed in the period of extended operation. Thus, risk significance may be considered in developing the details of an aging management program for the structure or component for license renewal, but may not be used to conclude that no aging management program is necessary for license renewal."

Therefore, the inspection interval of 5 years is adequate for monitoring general corrosion of carbon steel components exposed to a raw water environment in the circulating water system to assure corrective action is taken prior to loss of intended function.

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Item Reauest ResDonse 387 The ASME Code defines that stress intensity (SI) from two temperature transients is To address Environmentally Assisted Fatigue (EAF) for the NUREG/CR-6260 calculated from the stress components from the two conditions. Please explain how it locations at Vermont Yankee, the stress inputs for the reactor vessel and nozzles could be calculated from stress intensities of the two conditions derived from Greens were either taken from the design basis stress analyses or new stress analyses Functions, especially at locations of geometric discontinuity. Also, please justify the were performed. Existing stress analyses were used for the controlling locations on validity of combining the thermal transient stress intensities with the stress intensities the vessel shell and for the Recirculation Inlet nozzles. New stress analyses were from the external loads and pressure loading. performed for the Feedwater, Reactor Recirculation Outlet, and Core Spray nozzles per ASME III, NB-3200. Updated fatigue analyses for the reactor vessel and nozzles were performed per ASME III, Subsection NB-3222.

New fatigue analyses for the Class 1 portions of the Feedwater and Reactor Recirculation/RHR piping were performed per ASME Ill, NB-3600.

Finite element models (FEM) using ANSYS were developed for the new fatigue analyses of the Reactor Recirculation Outlet and Core Spray nozzles. The FEM for each nozzle is 2-D axisymmetric about the centerline of each nozzle. The radius of the vessel in the FEM was multiplied by a factor of two (2) to account for variation in pressure stress for a nozzle oriented normal to the cylindrical vessel shell.

For the Feedwater nozzles, a previously developed, 2-D axisymmetric ANSYS FEM was used. The vessel radius used in this model was 1.5 times the radius of the vessel. Pressure stresses from this model were factored by (2.0/1.5) = 1.333 to account for variation in pressure stress for a nozzle oriented normal to the cylindrical vessel shell.

For the new fatigue analyses of the Feedwater, Reactor Recirculation Outlet, and Core Spray nozzles, stress intensities due to internal pressure were calculated directly using the ANSYS FEM model.

The controlling location for thermal stresses at the safe end of each FEM was determined using a 5002F to 1009F temperature step transient at 100% flow conditions. The controlling location in the blend radius of each FEM was taken as the location of maximum stresses due to internal pressure.

Stress intensities for each thermal transient were determined using Green's function (GF) methodology. The GF at each controlling location was developed from the FEM stress results for the 5009F to 1009F temperature step transient. At each controlling location, absolute values of the component stress differences, (SZ-SX, SY-SX, SZ-SY), were compared to the maximum stress intensity calculated from ANSYS. For ease of calculation, the stress difference which most closely matched the total stress intensity calculated by ANSYS was used to determine the G F at each location. In most cases the maximum component stress difference with time matched the maximum stress intensity calculated by ANSYS. This shows that shearing stresses are negligible for the thermal transient at that location and the maximum component stress difference is the maximum stress intensity.

Stress components from attached piping loads at the controlling thermal stress locations were calculated separately using standard strength of materials equations. Stress intensities were calculated from the stress components per ASME Code,Section III, Subsection NB-3215. These stress intensities are referred to as the "hand calculation method" as described below.

To show that the GF'approach used to calculate alternating stress intensities for the 7:38:00 PM I 717412007 1:38:00 PM Page 141 of 150 11/14/2007 Page 141 of 150

Item Request Response thermal transients obtains results comparable to results from an ASME Code,Section III, Subsection NB-3222 calculation, a comparison with the results a previous fatigue calculation was conducted. This comparison used the identical FEM constructed for the VY Feedwater nozzle.

The VY ASME Code design fatigue calculation (VY-10Q-303) which was performed directly using ANSYS, was compared to the EAF calculation (VY-16Q-302) performed using the GF methodology for the turbine roll transient. This is the most severe design basis transient for VY Feedwater nozzle. To ensure a consistent comparison between the two calculations, the same stress path locations were selected. The Code fatigue calculation alternating stresses (using the limiting Sz-Sx stress difference) were extracted from the ANSYS model at the same paths used in the EAF calculation. To be consistent the Code FEM analysis was re-run with the same heat transfer coefficients and material properties used for the GF calculation.

The comparison showed that the alternating stress intensities calculated using the FEM with the Code methodology and those calculated with the GF methodology are

-within 1% at both the safe end and blend radius locations.

Although this comparison was for the feedwater nozzle, the results are considered to be equally applicable to all other nozzle locations based on a BWR Vessel and Internals Project (BWRVIP) study (EPRI Report No. 1003557, "BWRVIP-108: BWR Vessel and Internals Project, Technical Basis for the Reduction of Inspection Requirements for the Boiling Water Reactor Nozzle-to-Vessel Shell Welds and Nozzle Blend Radii," Final Report, October 2002.

In BWRVIP-108, 3-D models of four different nozzles were developed and analyzed that bounded all nozzle geometries for the BWR fleet. The results of this study showed that for a range of vessel nozzles modeled using the same technique, the ratio of maximum pressure stress intensity at the blend radius to the primary membrane stress intensity at the vessel wall away from the nozzle is nearly a constant with an average ratio that varies by +/- 3%. This indicates that all different sized BWR vessel nozzles have the same geometric characteristics for calculating peak stresses in the blend radius regions.

Figures 4-30 to 4-33 in BWRVIP-108 show the nozzle blend radius stress profiles for pressure and steady state thermal stresses for the four (4) different BWR nozzles.

The figures show a significant variation of pressure stress around the centerline of the nozzle with the peak hoop pressure stresses occurring at the +909 (top) and -90° (bottom) azimuths. This is due to the differences in hoop and axial stresses in a cylindrical vessel. The new FEM models used in the Vermont Yankee EAF evaluations were 2-D axisymmetric about the centerline of each nozzle. The radius of the vessel in the FEM was multiplied by a factor of two (2) to account for variation in pressure stress for a nozzle oriented normal to the cylindrical vessel shell.

Figures 4-30 to 4-33 in BWRVIP-1 08 also show no significant variance in steady state thermal stresses at the nozzle. The figures show the magnitude of axial stress at the 02 & 180- azimuths is equal to the magnitude of the hoop stress at +902 and -

90 2 azimuths. This shows that the thermal stress in the blend radius oriented normal to the axis of the nozzle is nearly constant. Thermal transients used in the EAF evaluations are localized to the nozzle safe end, bore, and blend radius regions. Therefore, the use of 2-D axisymmetric modeling vs. the use of a 3-D FEM is adequate to determine thermal transient stresses in both the safe end and blend 1111412007 1:38:00 PM Page 142 of 150

Item Request Response radius locations.

The adequacy of the hand calculations used to calculate mechanical load stresses is addressed as follows:

Stress intensities from the attached piping loads at the controlling thermal stress locations were calculated from stress components per ASME Section Il, Subsection NB-3215. For the feedwater nozzle of another BWR plant, hand calculations were performed for stresses due to mechanical loads. The hand calculations were performed using the same methodology as used for VY. These were compared to the results from a finite element model which included the mechanical loads applied directly to the model.

The finite element model was an axisymmetric two-dimensional (2-D) finite element model. This model was constructed and meshed in a very similar manner to the VY nozzle FEMs. Non-symmetric loading elements were used and the shear, moment, axial, and torsional loads were applied to the model.

A comparison of the stresses from the hand calculations vs. the FEM is as follows:

Location: Safe-End - Linearized Membrane + Bending Stress Stress from Hand Calculations (psi): 8863 Stress from FEM (psi): 5852 Difference, Hand Calc vs. FEM: +51.45%

Location: Safe-End - Total Stress Stress from Hand Calculations (psi): 8863 Stress from FEM (psi): 7855 Difference, Hand Calc vs. FEM: +12.83%

Location: Nozzle Forging - Linearized Membrane + Bending Stress Stress from Hand Calculations (psi): 1042 Stress from FEM (psi): 769 Difference, Hand Calc vs. FEM: +35.50%

Location: Nozzle Forging - Total Stress Stress from Hand Calculations (psi): 1042 Stress from FEM (psi): 554 Difference, Hand Calc vs. FEM: +88.09%

As shown by these results, use of the hand calculations is conservative compared to the FEM results. Stress intensities from attached piping loads are larger in the safe end section of each nozzle and are significantly reduced for the blend radius section due to the larger section thickness provided by the nozzle reinforcement. As shown in Table 3 of calculation VY-16Q-302 for the VY Feedwater nozzles, the maximum stress intensity from attached piping loads is 5708 psi for the safe end and 265 psi for the blend radius.

A comparison of the maximum stress intensity from the attached piping loads with the total stress intensity from the significant transients from Tables-4 and 5 of calculation VY-16Q-302 for the VY Feedwater Nozzle follows:

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Item Request Response Location: Table 5: Safe End Attached Piping Maximum Stress Intensity (psi): 5708.

Transient: No. 3: Startup, t = 16,328 sec.

Total Stress Intensity (psi): 14396.

Attached Piping Stress Intensity is 39.6 % of Total Transient: No. 4: Turbine Roll, t = 4 sec.

Total Stress Intensity (psi): 53379.

Attached Piping Stress Intensity is 10.7% of Total Transient: No. 11: Scram - LOFP, t = 2168 sec.

Total Stress Intensity (psi): 70223.

Attached Piping Stress Intensity is 8.1% of Total Transient: No. 20A: Hot Standby, t = 4 sec.

Total Stress Intensity (psi): 53379.

Attached Piping Stress Intensity is 10.7% of Total Location: Table 4: Blend Radius Attached Piping Maximum Stress Intensity (psi): 265.

Transient: No. 3: Startup t = 16,782 sec Total Stress Intensity (psi): 34282.

Attached Piping Stress Intensity is 0.8% of Total Transient: No. 4: Turbine Roll t = 1802 sec.

Total Stress Intensity (psi): 67667.

Attached Piping Stress Intensity is 0.4% of Total Transient: No. 11: Scram - LOFP t = 195 sec.

Total Stress Intensity (psi): 74567.

Attached Piping Stress Intensity is 0.4% of Total Transient: No. 20A: Hot Standby, t = 183 sec.

Total Stress Intensity (psi): 66298.

Attached Piping Stress Intensity is 0.4% of Total As shown in table above, the contribution to the total stress range from the attached piping loads is more significant for the safe end location and could effectively be ignored for the blend radius location.

Combining the thermal transient stress intensities directly with the stress intensities calculated from the external loads and pressure loading essentially combines the maximum principal stresses calculated for each load case. This allows for combination of stress results where different methods or models are used to calculate the stresses, and typically produces conservative results compared to combining all stress components and then determining a stress intensity.

The practice of combining stress intensities from thermal transient load cases directly with the stress intensities from mechanical loads vs. combining all stress components and then calculating a combined stress intensity was used by CB&I for 1111412007 :38:00 PM Page 144 of 150

Item Request Response the original design analyses for Vermont Yankee and by GE in the analyses for the replacement safe ends for the Reactor Recirculation Inlet and Outlet Nozzles.

For the evaluation of EAF for Vermont Yankee, the combination of thermal stress intensities with stress intensities from external loads and pressure was performed as follows:

The stress intensity calculated from external loading is added to the maximum calculated thermal transient stress intensity using the same sign to increase the stress range. This is necessary because the direction of applied loading from external loads is not known. The stress intensity from the external loads for each transient is scaled for the temperature of the transient assuming no stress occurs at 702F and full values are reached at reactor design temperature of 5752F. This maximizes the stress range pairings for the fatigue analysis. The pressure stress intensity value is added to the stress intensity from the combined thermal and external loadings directly as a positive value, since pressure is always positive due to the known direction of loading.

388 Provide justification for statement on page 5 of 34 of Calculation No. VY-1 6Q-302, that A calculation was performed by the vendor as part of the generic verification for the "The Greens Function methodology provides identical results compared to running the Green's function approach. The calculation compared the results from an ANSYS input transient through the finite element model." FEM analysis of a feedwater nozzle for a turbine roll transient with the results using Green's functions for the same transient. The results showed the stress range differences between the Green's function approach and the ANSYS FEM for the safe end location were between -0.06% and 3.43% and for the blend radius location were between -1.73% and 1.56%. These differences are considered well within the accuracy range of the analysis.

In addition, a VY specific comparison was made for the Feedwater nozzle as described in the response to question 387 above. The comparison showed that the alternating stress intensities calculated using the ANSYS FEM with the ASME Code methodology and those calculated with the GF methodology for the same transient inputs are within 1% at both the safe end and blend radius locations.

Further discussion of Green's functions and how they are used in a fatigue monitoring system is available in two papers. The papers are titled "An On-Line Fatigue Monitoring System for Power Plants: Part I - Direct Calculation of Transient Peak Stress Through Transfer Matrices and Green's Functions" and "An On-Line Fatigue Monitoring System for Power Plants: Part II - Development of a Personal Computer Based System for Fatigue Monitoring", ASME Pressure Vessel and Piping Conference, Vol.112, 1986 (Kuo, Tang, and Riccardella).

The intent of the statement in this and other calculations was to indicate that equivalent stress history results are obtained from each method (Green's function vs. FEM) for a given thermal transient.

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Item Reauest Resoonse Resconse 389 For the blend radius for the feedwater nozzle in Calculation No. VY-1 6Q-302, Table 4, The Green's functions are based on constant material properties and heat transfer Page 16: Why are the Total & M+ B stresses for Thermal Transient 3 shown in coefficients. Therefore, parameters were chosen to bound the transients that result columns 3 & 4 high at t=0 sec. (zero stress state?) This question also applies to: in the majority of the fatigue usage. The temperatures in the design transients Transient 4 at t =1801.9 sec. range from 100°-F to 549°-F. Material properties and heat transfer coefficients at Transient 9 at t = 2524 sec. 300°F were used. These bound the cold water injection events. In addition, the Transient 21-23 at t= 20144 sec. instantaneous value of the coefficient of thermal expansion is used instead of the This question may also apply to transients 11, 12, and, 14. mean value.

To maximize stresses in the blend radius, the Green's function was based on a fluid temperature shock of 500-F to 100-F in the nozzle flow path while the vessel wall portion of the model was exposed to a constant fluid temperature of 5002 F.

Therefore the reference point stress estimated from this Green's function at an ambient nozzle fluid temperature is non-zero due to the vessel wall being held at 500-F. The resulting stress ranges from the thermal transient analysis using the Green's function methodology are accurate regardless of the reference point used as long as the material properties used are consistent with the transient temperature range. With the above in mind, Table 4 of VY-1 60-302 was set up to yield stress pairings which ensure the calculated stress ranges would be maximized.

These temperature conditions are appropriate for Green's function integration of all feedwater nozzle transients which contribute to fatigue, since they occur with feedwater flow injecting through the nozzle into a hot vessel. in reality, these conditions are conservative for transients where there is no flow in the nozzle or for transients where the reactor temperature drops below 500'F. This is due to a large temperature gradient induced into the nozzle structure due to the temperature difference between the reactor and nozzle flow path portions of the model. This temperature difference leads to the high stress values observed for Transients 3, 14 and 21-23 at ambient temperatures.

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Item Request Response 390 Explain why there are differences in the calculated CUF values a between Rev. A and Calculations VY-16Q-301 through VY-1 6Q- 311 performed for VY and issued as Rev. 0 of the Structural Integrity Calculations. Also, why are the CUFs calculated by Revision A have the Revision Description on each calculation cover sheet labeled as Structural Integrity different from the CUFs shown in Tables 4.3.1 & 4.3.3 of the "Initial Draft for Review". These draft calculations were issued for client review and Vermont Yankee License Renewal Application? comment. The draft versions of the calculations were never intended to be the issued version until all inputs were finalized and all external and internal reviews and comments were incorporated. The Revision A calculations were provided under Entergy's obligation to provide all documents related to Environmentally Assisted Fatigue for NEC Contention 2.

The Revision 0 versions of these calculations were subsequently issued after comments on the draft calculations were resolved and all design inputs finalized and verified. Revision 0 (or later) versions of the calculations are the Calculations of Record. The Revision A drafts are no longer applicable.

The Revision 0 calculations and reports incorporated reviewer comments which included; expanded descriptions of the methodologies and analyses, additional references, typographical corrections, and component specific technical comments which affected the final CUF values.

Referring to Table 3-10 in the Summary Report, SIR-07-132-NPS (VY-16Q-404), the most significant changes from Revision A to Revision 0 for 60 year environmental CUFs greater than 0.50 were for the Feedwater nozzle and the Reactor Recirculation / RHR piping.

Specific inputs which affected the CUF for the Feedwater nozzle included increased pressure stresses and reduced thermal stress inputs for isothermal events. The Revision 0 calculation for the Feedwater nozzle (VY-16Q-302) shows the blend radius as the limiting section vs. the safe end as the limiting section in Revision A.

This resulted in an increase in the 60 year CUF from 0.0127 to 0.0636 and an increase in the 60 yr environmental CUF from 0.127 to 0.639 at the Feedwater nozzle blend radius.

Corrections to the transient temperature inputs for the Reactor Recirculation / RHR piping model resulted in the maximum calculated CUFen = 0.7446 at the RHR return tee location. The draft Revision A of the calculation had the RHR suction tee controlling.

The CUFs shown in Tables 4.3.1 & 4.3.3 of the Vermont Yankee License Renewal Application were based on the design basis fatigue evaluations factored to account for the effects of the 120% Extended Power Uprate. For locations with no plant specific CUFs, representative values from NUREG/CR-6260 were used.

The CUFs calculated for the Environmentally Assisted Fatigue evaluation are different from the CUFs shown in the VY LRA due to a number of factors specific to each location. These include:

lupdated finite element modeling (FEM) vs. the shell analysis techniques used in the original design analysis,

Odirect thermal transient analysis using the FEM vs. the separate thermal analyses to determine temperature distributions used in the original design analyses,

-Ouse of updated transient definitions for 60 years of operation. The updated transient definitions are shown in Design Input Record (DIR) for EC No. 1773, Rev.

0, "Environmental Fatigue Analysis for Vermont Yankee Nuclear Power Station" Page 147 of 150 11114121 1:38:00PM 11/1 4/20077 1:38:00 R Page 147 of 150

Item Request Response Revision 1, dated 7/26/07.

For the NUREG/CR-6260 locations without existing fatigue analyses, new VY plant-specific ASME III fatigue analyses were performed.

391 On page 1-1 of Report VY-16Q-401 it indicates that refined transient definitions 60 The original design transients for the VY Reactor Vessel are given in Section 5.1.8 years are used in the computation of the CUF including EAF effects. Please explain and Attachment D to General Electric Purchase Specification No. 21A1115, the refinements in the transient definitions. "Reactor Pressure Vessel", Revision 4, 10/21/69 and certified on 10/23/69 as contained in the Reactor Pressure Vessel Design Report. This document is the Vermont Yankee Reactor Vessel Design Specification. Additional clarifications and descriptions for the design transients were provided by General Electric in GE Letter W. J. Zarella to D.W. Edwards - Yankee Atomic,

Subject:

"V. Y. R.P.V.

Temperature Transient / Cycling Events", No. G-HB-5-124, dated November 5, 1975.

Earlier versions of the specification made reference to a GE Thermal Cycle Drawing No. 885D941. The final version of the design specification relocated this cycle information to Attachment D of the specification and deleted references to GE drawing No. 885D941.

r Comparisons were made between the VY Design Specification transients and the design transients shown on Thermal Cycle Drawings from other GE BWR 4 plants of the same and later vintage. The later plants have more detailed thermal cycle descriptions based on the experience from the earlier GE BWRs.

In general, VY is designed for a smaller spectrum of the most severe transients as compared to the full spectrum of transients used for the later units. As described in General Electric Letter No. G-HB-5-124, the number of cycles for each VY design transient exceeds the number of cycles for the same transient from the typical GE thermal cycles diagram listed in the original VY FSAR. For example; the single severe design transient for the VY Feedwater nozzle of 1500 cycles exceeds the 518 Start-up, Loss of Feedwater Heater, Scram, and Shutdown events listed in the original VY FSAR.

To insure a realistic projection of design thermal transient cycles and events for 60 years of operation, the Thermal Cycle Diagrams used at a number of BWR 4 plants were used as a starting point. The VY Design Specification transients were mapped onto the typical BWR 4 Transient Diagram. Then projections for 60 years were made based on the numbers of cycles in the VY Design Specification, the numbers actually analyzed in the VY Design Certified Stress Report for Vermont Yankee Reactor Vessel, Chicago Bridge & Iron, Contract 9-6201, and the number of cycles experienced by VY in approximately 35 years of operation. For all Service Level A &

B events, the 60-year projected cycles for each transient used in the EAF evaluations exceed the actual number of cycles experienced by VY projected to 60 years of operation. The basis for the 60 year transient definitions is documented in Appendix C of calculation VYC-378 Revision 2.

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Item Request Response 392 For the Feedwater Nozzles there are large differences in the CUFs without the Fen The original Design Transient for the VY Feedwater nozzle is given in Attachment D factors shown in shown in Table 4.3.1 of the Vermont Yankee License Renewal to GE Specification No. 21A1115, "Reactor Pressure Vessel", Revision 4, Application and those shown in calculation VY-16Q-302. Section 2.0 of the calculation 10/21/69. It is a single severe design transient intended to envelop all Start-up, on page 4 of 32 states, " ... several of the conservatisms originally used in the original Loss of Feedwater Heater, Scram, and Shutdown events. It consists of 1500 cycles feedwater evaluation (such as grouping of transients) are removed.. Please explain of:

what conservatisms were removed.

- Feedwater nozzle at 546-F steady state and 0% feedwater flow, followed by,

- Step change from 546°F to 100-F with 25% feedwater flow, followed by,

- Feedwater nozzle at 1002F steady state and 25% feedwater flow, c followed by,

- Step change from 100-F to 260-F, followed by,

- A ramp from 260-F to 376S-F at 250-F/Hr concurrent with increasing feedwater flow 25% to 100% rated flow.

This transient is equivalent to a Startup and Turbine Roll event combination specified on newer BWR plant Thermal Cycle Diagrams.

As described in GE Letter No. G-HB-5-124, dated November 5, 1975, the 1500 such events considered in the design fatigue evaluation of the Feedwater nozzle exceed the 518 Start-up, Loss of Feedwater Heater, Scram, and Shut- down events listed in the original FSAR.

The CUF for the Feedwater nozzle shown in Table 4.3.1 of the Vermont Yankee License Renewal Application is based on the design basis fatigue evaluations factored to account for the effects of the 120% Extended Power Uprate (EPU).

Changes in temperatures for EPU are from GE Nuclear Energy Certified Design Specification No. 26A6019, "Reactor Vessel - Extended Power Uprate", Rev. 1, 8/29/03.

The evaluation of EPU effects on the feedwater nozzle and safe end stress and fatigue analysis is contained in VY Engineering Report, VY-RPT-05-001 00, Rev. 0, "Task T0302 Reactor Vessel Integrity-Stress Evaluation EPU Task Report for ER 1409". Section 3.3.1.1 of GE Report for Task 302, shows the value for the feedwater nozzle safe end EPU CUF for 40 years = 0.75. This is the value shown in Table 4.3.1.

The 0.75 CUF value is based on the original design report. The original design analysis was performed for "loose fit" feedwater spargers where the annular cold gap between the stainless steel thermal sleeve and the nozzle safe end was 0.020 inch. The feedwater spargers and thermal sleeves were replaced in 1976 with new "interference fit" thermal sleeves. The interference fit thermal sleeves significantly reduce leakage flow past the thermal sleeve into the bore region of the nozzles. This reduces the heat transfer from the process fluid to the nozzle base metal, thereby reducing thermal stresses during system thermal transients.

Subsequent to the GE report, a re-analysis of the Feedwater nozzle was performed.

Report No. SIR-04-020 Revision 0, March 2004. "Updated Stress and Fatigue Analysis for the Vermont Yankee Feedwater Nozzles" documents a revised ASME III Stress and Fatigue Analysis for the Feedwater nozzle and safe end. This PM 1:J5:UU PM 77/14/ZfJU7 1:38:00 Page 149 of 150

1111412007 Page.149 of 150

Item Request Response analysis included effects of the interference fit thermal sleeve. The analysis was performed for both the original licensed power and system flow rates using the enveloping design transient, "Startup, Loss of Feedwater Heaters, Scram &

Shutdown", from the original Design Specification-and for EPU power and flow conditions as modified per the EPU Design Specification. For the nozzle safe end, the 40-year CUF using 1500 cycles of the enveloping transient and including EPU effects = 0.4513 (as compared to the 0.75 value used in the LRA). The primary reason for the decrease in CUF was a result of the improved heat transfer coefficients resulting from the interference fit thermal sleeve.

The calculated fatigue usage for the safe end prior to the installation of the interference fit thermal sleeve using the actual number of startup and shutdown cycles andthe allowable number of cycles from the original CB&I design report is 0.02. As documented in Appendix D to calculation VYC-378, Rev. 2, this has a negligible effect on the revised CUF for the safe end including EPU effects shown above. This is primarily due to conservatisms in the Updated Feedwater Fatigue Analysis for the number of cycles operating under EPU conditions.

For the Environmentally Assisted Fatigue (EAF) evaluation, (VY-1 6Q-302), a realistic projection of Design Thermal Transient Cycles and Events for 60 years of operation based on the Feedwater Nozzle Thermal Cycle Diagram from a typical BWR 4 was used. A described in the response to Question 391, the enveloping design transient was mapped to the "Turbine Roll & Increase to Rated Power" transient. Other transients including Loss of Feedwater Heaters and Scram events were taken directly from the typical BWR 4 Feedwater Nozzle Thermal Cycles Diagram using VY specific EPU design pressures and temperatures. The projections for 60 years were based on the number of events in the VY Design Specification, the numbers analyzed in the VY Design Certified Stress Report for VY Reactor Vessel, and the number of cycles experienced by VY in approximately 35 years of operation.

The design transients used in the EAF evaluation for the VY Feedwater nozzle are shown in Attachment 1 to Design Input Record (DIR) for EC No. 1773, Rev. 0, "Environmental Fatigue Analysis for Vermont Yankee Nuclear Power Station" Revision 1, dated-7/26/07.

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BVY 07-079, Update of Aging Management Program Audit Q&A Database

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