ML12171A521

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Pre-Filed Hearing Exhibit NYS000389, NRC Request for Additional Information Re IP2 and IP3 License Renewal Application, (Feb. 10, 2011)
ML12171A521
Person / Time
Site: Indian Point  Entergy icon.png
Issue date: 02/10/2011
From: Kimberly Green
Division of License Renewal
To:
Indian Point
SECY RAS
Shared Package
ML12171A508 List:
References
RAS 22624, 50-247-LR, 50-286-LR, ASLBP 07-858-03-LR-BD01
Download: ML12171A521 (16)
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Text

{{#Wiki_filter:NYS000389 Submitted: June 19, 2012 UNITED STATES NUCLEAR REGULATORY COMMISSION WASHiNGTON, DoG- 2055-5-0*Jt!~ February 10, 2011 Vice President Operations Entergy Nuclear Operations. Inc Indian Point Energy Center 450 Broadway, GSB P,O, Box 249 Buchanan, NY 10511-0249

SUBJECT:

REQUEST FOR ADDITIONAL INFORMATION FOR THE REVIEW OF THE INDIAN POINT NUCLEAR GENERATING UNIT NUMBERS 2 AND 3, LICENSE RENEVv'AL APPLICATION

Dear Sir or Madam:

By letter dated April 23, 2007, as supplemented by letters dated May 3, 2007, and June 21. 2007, Entergy Nuclear Opeiations. Inc., (Entergy) submitted an application puisuant to Title 10 of the Code of Federai Reguh:Jtions Pari 54, to renew the operating licenses for indian Point Nuclear Generating Unit Nos. 2 and 3, for- reviet.AJ by the U.S. Nuciear Reguiatory Commission (NRC or the staff) The staff documented it~ findings in the Safety Evaluation Report Related to the License Rene'wval of Indian Point Nuclear Generating Unit Nos. 2 and 3 \rVhich -...vas issued in August 2009. Since the issuance of the safety evaluation report. the staff has identified the need for additional information with respect to c.ertain aging management programs based on lessons !earned from past LR.A.s and recent industry operating experience. Additionally. the staff has identified issues that need additional c!ar!flcation for the license renevva! application. Therefore! the staff requests additional information as described in the enclosure. !terns in the enclosure were discussed with Mr. Robert Wa!po!e, and a mutua!!y agreeable date for the response is within 45 days from the date of this letter. !f you have any questions, p!ease contact me at 301-415-1627, or v1a e-mail at Kimberly,Green@nrc,gov Sincerely, v' t ~ .

  • t~_, ~

I \IJ..;.)JI,).J.J{{ u7 ~ (/  ! Kimberly J, Green, Safety Project Manager Projects Branch 2 Division oi License Renewal Office of Nuciear Reactor Regulation Docket Nos. 50-247 and 50-286 Enciosure. As stated cc \tl/cnc!: Distribution via Listsent OAGI0000965_00001

INDIAN POINT NUC:LEAR GENERATING UNIT NUMBERS 2 AND 3 LICENSE RENEWAL APPLICATION REQUEST FOR ADDITIONAL INFQRMAIIQf\1 RA! 3.0.3.1.2-1 BACKGROUND in light of Operating Experience (OE} that has occurred coincident with and after the U.S. Nuciear Regulatory Commission (NRC or the staff) evaluation of the indian Point License Renewal Application (LRA) and issuance of the Safety Evaluation Report (SER), the staff is concerned about the cont1nued susceptibility to failure of buned (i.e., piping in direct contact with soil) and/or underground piping (i.e., piping not in direct contact with soil, but located below grade in a vault, pipe chase, or other structure where it is exposed to air and where access is limited) that is within the scope of Title 10 of the Code of Federal Regulations (1 0 CFR) 54.4 and subject to aging management for license renewal. The staff reviewed the LRA, SER and a letter dated July 27, 2009, from the applicant addressing buried pipe program modifications as a result of recent site operating experience. Based on the review of these documents subsequent to the recent industry OE, the staff does not have enough information to evaluate how Indian Point is implementing changes to their program based on the industry experience ISSUE

1. The LRA and supplemental material did not contain enough specifics on the planned inspections foi the staff to determine if the inspections would be adequate to manage the aging effect for all types/materials of in-scope buried pipes [e.g., safetyicode ciass and potentiai to release materials detrimental to the environment (e.g., diesel fuel and radioisotopes that exceed Environmental Protection Agency drinking water standards)].
2. The staff believes that buried coated steel piping is more susceptible to potential failure if it is not protected by a cathodic protection system unless soil resistivity is greater than 20,000 ohm-em.
3. The LRA and supplemental material did not contain enough specifics for the staff to understand the general condition of the backfill used in the vicinity of buried in-scope piping.
4. In a letter dated July 27, 2009, the applicant stated that it \.'Vi!! employ qualified inspection methods 'vvith demonstrated effectiveness for detection of aging effects during the period of extended operation. The staff acknowledges that where examining buried pipe from the exterior surtace is not possible due to plant configuration (e.g., tr1e piping is located underneath foundations) it is reasonable to substitute a volumetric examination from the interior of the pipe provided the surface is properly prepared. However, beyond ultrasonic techniques, the staff is not aware of another reliable volumetric inspection methodology that is suitable for inspecting buried in-scope piping. This is particularly true, in light of industry experience, with guided wave ultrasonic technology.

ENCLOSURE OAGI0000965_00002 

                                                      . 2.
5. Based on a review of the LRA and UFSAR. it is not clear to the staff what in-scope systems (if any) have underground p!p!ng or 1f such piping will receive inspections consistent \*vlth the program described in External Surfaces Monitoring Program.
6. LRA Sections A.2.1.5 and A.3.1.5 states that corrosion risk vvm be determined through consideration of material, soil resistivity, drainage, presence of cathodic protection and type of coating. Given that cathodic protection has not been Installed for ali buried in-scope piping, the staff lacks sufficient information io conciude thai the applicant's evaluation of soil corrosiviiy will provide reasonable assurance thai in-scope buried pipmg will meet its intended iicense renewal function(s). Specifically, the staff is concerned with the following:
a. While the applicant stated that it will include consideration of soil resistivity and drainage, it did not state that other important soil parameters would be included such as, pH, chlorides, redox potential, sulfates and sulfides.
b. The applicant did not state how often it will conduct testing of localized soil conditions, nor provide the specific locations relative to buried in-scope piping that is not cathodically protected.
c. The applicant did not state hov: they 'Nou!d integrate the various soil parameters into an assessment of corrosivity of the soil, such as using "Assessment of Overafl Soil Corrosivity to Steel, 1 or A'v"'../V".JA C1 05 2.
d. Tt*1e applicant did not specificaiiy state how iocaiized soii data wiil be factored inio increased inspections, including the specific increase in the number oi committed inspections by material type and location.

REQUEST

1. Respond to the following:
a. Describe how many in-scope buried piping segments for each material, code/safety-related piping, and potential to release materials detrimental to the environment category wi!! be inspected.
b. For the 45 planned inspections prior to the period of extended operation:
i. Ho*N many v.ti!l consist of an excavated direct visual inspection of the externa! surfaces of the buried pipe?

iL \.l\fhat length of piping will be excavated and f1ave a direct visual inspection conducted? 1 Assessment of Overa!! Soit Corrosivity to Steel, C.P. D!!!on, Corrosion Contra! in the Chemica! Process Industries, Sec.ond Edition, Materials Technology !nst!tute of the Chemica! Process Industries, !nc. and Washington Suburban Sanitary Commission 2 ANSI/A_WNA C105/A21 5, "Polyethylene Encasement for Ducti!e-!ron Pipe Systems." OAGI0000965_00003

co Understanding that the total number of inspections performed will be informed by p!ant~specific and industry operating experience, what minimum number of inspections of buried in-scope piping is planned during the 40 -50 and 50- 60 year operating periods? VVhen describing the minimum number of planned inspections, differentiate betvveen material, code/safety-related piping, and potential to release materials detrimental to the environment category piping inspeciion quaniiiies of buried in-scope piping.

d. What specific inspections will be performed for the IP3 security generator propane tank and at what frequency?
2. Respond to the follovviog:
a. Confirm at IP2 that the service water system and at IP3 that the service water suction piping are the only in-scope steel piping systems currently protected by a cathodic protection (CP) system bo For those systems that are protected by a CP system:
              !. Has annua! N.ACE survey testing been conducted, and if so, for how many years?
n. Have the output of the beds been trended, and if so, 1.vhat are the results of the trending?

iii. \'Vhat is the availability of the cathodic piotection system?

c. For buried in-scope sieei piping systems thai are not caihodicaiiy protected:
i. Justify why this piping wili continue to meet or exceed the minimum design waii thickness throughout the penod of extended operatiOn, assuming that no coatings are applied to the piping. or ii. Justify why the number of the planned inspections of this piping is sufficient to reasonably assure that this piping will continue to meet or exceed the minimum design wall thickness throughout the period of extended operation.
3. RA~nnnd to thA fo!!owinn:
a. Provide details on any further excavations conducted since Ju!y 2009 that provide insight on the extent of condition of the quality of the backfill in the vicinity of buried pipes.
b. if there Is no further lnforrnation on the condition of the quality of backfiil, justify why the planned inspections are adequate io detect poieniiai degradation as a resuit of coating damage, particularly in steel buried pipe systems that are not protected by a CP system.

OAGI0000965_00004

4. R©§Q()ncJJpJhe following:

a In absence of a qualified method, and until such time that one is demonstrated to be effective, what alternative inspection methods wi!l Entergy employ when excavated direct vi sua! examinations are not possible due to p!ant configuration.

b. Justify vvhy the methods identified ~n response to request 4a 'Nil! be effective at providing ieasonable assurance that the buried in-scope piping systems win meet their current licensing basis function.
c. if a volumetric examination method is used, what percentage of interior axial iength of the pipe wiii be inspected?
5. For in-scope underground piping, respond to the following:
a. State what systems have underground piping and indicate the corresponding length of piping.
b. State how often and what quantity of underground piping for each system will be inspected by an aging management program (AMP), and indicate which AMP will be used.

6, Respond to the fo!!o\"'Jing for buried in-scope stee! piping without cathodic protection:

a. State what soil parameters vvill be included in the analysis of soil coiiosivity beyond soil resistivity and drainage.
b. State how often soil sampling wiil be conducted and in what iocations.
c. State how the various soil parameters will be integrated into an assessment of the corrosivity of the soil.
d. State how localized soil conditions will be factored into increased inspections, including the specific increase in the number of committed inspections by material type and location RA! 3.0.3.1.6-1 BACKGROlJND NUREG-1801, Rev. 1, "Generic Aging Lessons Learned (GALL) Report," (the GALL Report) addresses inaccessible medium-voltage cables in Aging ivianagement Program Xi.E3, "inaccessible iviedium Voltage Cables Not Subject to *j 0 CFR 50.49 Environmental Quaiification Requirements." The purpose of this program is to provide reasonable assurance that the intended functions of inaccessible med1um-voltage cables (2 kV to 35 kV), that are not subject to environmental qualification requirements of 10 CFR 50.49 and are exposed to adverse localized environments caused by moisture while energized, will be maintained consistent with OAGI0000965_00005

the current licensina basis. The scooe of the oroaram aoolies to inaccessible (in conduits, cable trenches. cable trot3'ghs, duct banks: undergr~und vault~ or direct buried installations) medium-voltage cab!es within the scope of !lcense renewal that are subject to significant moisture simultaneously \*"'ith significant voltage. The application of GALL Report AMP XI.E3 to medium-voltage cables vvas based on the operating experience available at the time Revision 1 of the GALL Report was developed. However, recently-identified industry operating experience indicates that tf1e presence of water or moisture can be a contributing factor 1n inaccessible power cables failures at lower service voltages (480 V to 2 kV). Appiicable operating experience was identified in licensee responses to Genenc Letter (GL) 2007-01, "Inaccessible or Underground Power Cable Faiiures that Disable Accident Mitigation Systems or Cause Plant Transients,' which included failures of power cable operating at service voltages of less than 2 kV where water was considered a contributing factor. Recently-identified industry operating experience provided by NRC licensees in response to GL 2007-01 has shown: (a) that there is an increasinq trend of cable failures with len!:lth in service beginning in the 6"' through 1o'h years of operation and, (b) that moisture intrusion is the predominant factor contributing to cable failure. The staff has determined, based on the review of the cab!e failure d~stribution, that an annual inspection of manholes and a cable test frequency of at !east every six years is a conservative approach to ensuring the operability of pov;er cables and, therefore, should be considered. In addition, recently-identified industry operating experience has shown that some NRC licensees may experience cable manhole water intrusion events, such as flooding or heavy rain, thai subjects cabies within ihe scope of program for GALL Report AMP Xi.E3 to significant moisture. The staff has determined thai event driven inspections of cabie manholes, in addition to a one-year periodic 1nspect1on frequency, 1s a conservative approach and, therefore, should be considered. ISSUE The staff has concluded, based on recently-identified industry operating experience concerning the failure of inaccessible low voltage power cables (480 V to 2 kV) in the presence of significant moisture, that these cables can potentially experience age related degradation. The staff noted that the applicant's !naccessib!e Medium-Voltage Cables Program does not address inaccessible !0\.tv-vo!tage povver cab!es [400 V (nominally 480 V) to 2 kV inclusive]. !n addition, more frequent cab!e test and cable manhole inspection frequencies (e.g., from ten and two years to six and one year, respectively) should be evaluated to ensure that the Non-EQ Inaccessible Medium-Voltage Cable progiam test and inspection frequencies ieflect industry and plant-specific operating experience and that test arid inspectior1 frequencies may be increased based on future industry and piani-specific operating experience. REQUEST Provide a summary of your evaluation of recently identified 1ndustry operating experience and any plant-specific operating experience concerning inaccessible low voltage power cable failures within the scope of license renewal (not subject to 10 CFR 50.49 environmental OAGI0000965_00006

qualification requirements), and how th!s operating experience applies to the need for additional aging management activities at your pfant for such cables.

1. Explain how Entergy will manage the effects of aging on inaccessible lovv voltage povver cabies within the scope of iicense renewal and subject to aging management review; with consideration of recently identified industry operating experience and any plant-specific operatmg experience. The discussion should include assessment oi your aging management program description, program elements (i.e., Scope of Program, Parameters Monitored/Inspected, Detection of Aging Effects, and Corrective Actions),

and FSAR summary description to demonstrate reasonable assurance that the intended functions of inaccessible low voltage power cables subject to adverse localized environments will be maintained consistent with the current licensing basis through the period of extended operation.

2. Provide an evaluation showing that the proposed Non-EO Inaccessible Medium-Voltage Cable Program test and inspection frequencies, including event-driven inspections, incorporate recent industry and plant-specific operating experience for both inaccessible
        !ow and medium voltage cab!e.
3. In Commitment 40, Entergy committed to evaluate plant-specific and industry operating experience prior to enteiing the period of extended operation. Explain how the proposed Non-EQ Inaccessible Medium-Voltage Program will continue to ensure tflat future industry and piant-specific operating experience wiii be incorporated into the program such thai inspection and iesi frequencies may be increased based on test and inspection results.

RAI 3.0.3.1.10-1 BACKGROUND By letter dated July 26, 2010, the applicant provided clarification of LRA Section 8.1.28, "One Time Inspection- Small Bore Piping_" The appHcant stated that its fnservice fnspection (!S!) Program includes periodic volumetric examinations on AS~ilE Code Class 1 sma!!-bore socket \*ve!ds. The applicant further stated that the inspection volume is ln accordance v;ith guidelines established in ~"~RP~ 146 'v-Vhich recommends examination of the base metal one-half inch beyond the toe of the weld. The applicant also cited recent plant-specific operating experience fn which leakage was detected in a Class 1 socket weld, and referenced the related Licensee Event Report (LER#2010-004-00). The staff noted that the appiicant did not provide information ihai supports iis conciusion on the faiiure mechanism. The staff noted that for IP2, the facility operatmg license (OPR-26) expires at midnight September 28, 2013, and for IP3, the facility operating license (DPR-64) expires at midnight December 12, 2015. The staff further noted that both IP2 and IP3 will be in their 4'h lSI interval upon entering the period of extended operation. OAGI0000965_00007

ISSUE The staff noted that the inspections performed by its !nservice Inspection Program for ASME Code C!ass 1 sma!!-bore socket vve!ds only include the base meta!, one-ha!f inch beyond the toe of the \Veld. It is not c!ear to the staff hov.: an inspection of the base meta!, one-ha!f inch beyond the toe of the v.teld, is capable of detecting cracking in the ASME Code Class 1 smail~bore socket weld metaL REQUEST

i. Explain how Entergy will manage aging (i.e., cracking) in the weid meiai of ASME Code Class 1 small-bore socket welds.
2. Clarify if the inspection volume selected for the proposed volumetric examinations of ASME Code Class 1 small-bore butt welds, performed by the One-Time Inspection- Small-Bore Piping Program, includes the weld metal. If it does not include the weld metal. justify that the inspection volume is sufficient and capable of detecting cracking in the ASME Code Class 1 small-bore butt weld metaL
3. Based on the operating experience at Indian Point, justify that an aging management program that performs periodic volumetric inspections of the we!d meta! for ASME Code C!ass 1 sma!!-bore socket and butt \Ne!ds is not necessary !n heu of this justification.

provide an aging management program that includes periodic volumetric inspections to manage cracking in small~bore piping and the associated vveld metal (socket vveld metal and butt weld metal).

4. Whether a one-time inspection program or periodic inspection program is selected, clarify the implementation schedule of the inspections for ASME Code Ciass i small-bore p1p1ng mclud1ng the associated welds (socket welds and butt welds).

RAI 3.0.3. 1.1 0-2 BACKGROL)J:IID SRP-LR Section A 1 2.3.4 states that when sampling is used a basis should be provided for the inspection population and samp!e size. The "monitoring and trending" program element of G.8~LL .8~MP X!.M35 recommends that the volumetric inspection should be performed at a sufficient number of locations to assure an adequate sample. Furthermore, this number, or sample size, will be based on susceptibility, inspectability, dose considerations, operating experience, and Hrniting locations of the total population of ASME Code Class i smaii-bore p1p1ng locations. iSSUE The staff noted that the applicant did not provide its basis for the sample size that it selected. Specifically, the weld populations and the sample size were not provided to the staff, therefore it is not clear to the staff what percentage of ASME Code Class 1 welds, both full penetration OAGI0000965_00008

welds and socket welds, will be inspected It is also not clear to the staff if a sufficient number of locations wiH be selected to ensure an adequate sample. REQUEST Provide the totai popuiations of AStv1E Code Class 1 small-bore butt welds and socket welds at indian Point for each unii. justify thai the number of samples, for boih buii welds and socket welds, is sufficient to ensure that an adequate sam pie is selected for inspections io be performed. RAI 3.0.3.2.10-1 BACKGROUND NRC staff has determined that masonry walls that are within the scope of license renewal should be visually examined at least every five years, with provisions for more frequent inspections in areas where significant !oss of materia! or ere. eking is observed_ !SSUE The LRA did not discuss the inspection interval for in~scope masonry vvalls. REQUEST 1-'rov1ae the inspection interval ror In-scope masonry wails. if the interval exceeds five years, clearly explain why and how the interval w1ii ensure that there 1s no loss oi Intended iunct1on between inspections. RAI 3.0.3.2.15-1 BACKGROUND NRC staff has determined that adequate acceptance criteria for the Structures Monitoring Program shou!d !nc!ude quantitative limits for characterizing degradation. Chapter 5 of ,ll,C! 349.3R provides acceptable criteria for concrete structures. lf the acceptance criteria in ACI 349.3R are not used, the plant-specific criteria should be described and a technical basis for deviation from ACI 349.3R should be provided. iSSUE The LRA did not clearly identify quantitative acceptance criteria for the Structures Monitoring Program inspections. REQUEST

1. Provide the quantitative acceptance criteria for the Structures Monitoring Program. If the OAGI0000965_00009

criteria deviate from those discussed in ,.t:l,C! 349.3R, provide technical justiflcation for the differences_

2. H quantitative acceptance criteria wiil be added to the program as an enhancement) state wheiher Entergy pians to conduci an inspeciion wiih the quantitative acceptance critena prior to the period of extended operation. if there are no plans to conduct an inspection with quantitative acceptance critena prior to entering the period of extended operation, explain how Entergy plans to monitor and trend data.

RAI 3.1.,2,2,13.c1 BACKGROUND SRP-LR Section 3.1.2.2.13 identifies that cracking due to primary water stress corrosion cracking (PVVSCC) could occur in P\A!R components made of nicke! a!!oy and stee! with nickel a!!oy cladding, including reactor coolant pressure boundary components and penetrations inside the RCS such as pressurizer heater sheathes and sleeves, nozzles, and other intern a! components. GALL Report Volume 2, Item IV.D1-06, recommends Chapter XI.M2, \AJater Chemistry," for PVVR piimary water to manage the aging effect of cracking in the nickel alloy steam generator (SG) divider plate exposed to reactor coolant. LRA Tabie 3. *u, item 3. U -8i, credits the \!Vater Chemistry Control- Primary and Secondary Program to manage cracking due to PWSCC in nickel-ailoy steam generator primary channel head divider plate exposed to reactor coolant in the steam generators, and LRA Table 3.1.1, item 3.1.1-82, indicates that the SG primary side divider plates are composed of nickel alloy. Unit 2 FSAR Section 4.2.2.3 and Table 4.2-1 describe the construction materials for the replacement Model 44F steam generators. The staff noted that there is no information about the construction materials of the divider plate assembly for the Unit 2 steam generators. Unit .3 FSAR Section 4.2.2 and Tab!e 4.2-1 describe the construction materials for the replacement Mode! 44F steam generators. The staff noted that there is no information about the construction materials of the divider p!ate assembly for the Unit 3 steam generators. ISSUE In some foreign steam generators with a simiiar design to tl1at of indian Point Units 2 and 3 steam generators, extensive cracking due to P'vVSCC has been identified in SG divider plate assemblies made with Alloy 600, even with proper primary water chemistry. Specifically, cracks have been detected in the stub runner, very close to the tubesheetlstub runner weld with depths of almost a third of the divider plate thickness. Therefore, the staff noted that the Water Chemistry Control -Primary and Secondary Program may not be effective in managing the aging effect of cracking due to PWSCC in SG divider plate assemblies. Although these SG divider plate assembly cracks may not have a significant safety impact in and of themselves, such cracks could affect adjacent items that are part of the reactor coolant pressure boundary (RCPB), such as the tubesheet and the channel head, if they propagate to OAGI0000965_00010

the boundary with these items For the tubesheet, PWSCC cracks in the divider plate could propagate to the tubesheet cladding with possible consequences to the integrity of the tube-to-tubesheet \Velds. For the channel head, the PVVSCC cracks in the divider plate could propagate to the SG triple point and potentially affect the pressure boundary of the SG channel head_ REQUEST

1. Discuss the materials of construction of the Units 2 and 3 SG divider plate assemblies, including the welds within these assemblies and to the channel head and to the tubesheet.
2. If any constitutive/weld material of the SG divider plate assemblies is susceptible to cracking (e.g., Alloy 600 or the associated Alloy 600 weld materials), explain how Entergy plans to manage PWSCC of the SG divider plate assemblies to prevent the propagation of cracks into other items that are part of the RCPB. whereby it challenges the integrity of the adjacent items.

RA! 3.1.2.2.16-1 BACKGROUND SRP-LR Section 3.1.2.2.16 identifies that cracking due to PVVSCC could occur on u-1e ptirnary cooiani side of PvVR sieei SG iube-io-iubesheei welds made or clad with nickel aiioy. The GALL Report recommends ASME Section XI lSi and control of water chemistry to manage this aging effect and recommends no further ag1ng management rev1ew for PWSCC ot nickel alloy 1f the applicant complies with applicable NRC Orders and provides a commitment in the FSAR supplement to implement applicable (1) Bulletins and Generic Letters and (2) staff-accepted industry guidelines. In GALL Report Revision 1, Volume 2, this aging effect is addressed in item IV.D2-4, applicable only to once-through SGs, but not to recirculating SGs. The staff noted that ASME Code Section XI does not require any inspection of the tube-to-tubesheet welds. In addition, there are no NRC Orders or bulletins requiring examination of this we!d. However, the staff's concern is that, if the tubesheet cladding is .A.!!oy 600 or the associated Al!oy 600 we!d materials, the tube-to-tubesheet vve!d region may have insufficient Chromium content to prevent initiation of PVVSCC. Similarly, this concern applies to SG tubes made from Alloy 680TT. Consequently, such a P\".JSCC crack initiated in this region, close to a tube, could propagate into/through the weld, causing a faHure of the weld and of the reactor coolant pressure boundary, for both recirculating and once-thr-ough steam generators. in LRA Tabie 3. i. i, item 3.-i. i-35, the appiicant stated that the corresponding GALL Report line appiies to once-through steam generators and was used as a comparison for the steam generator tubesheets. The applicant further stated that for the steel w1th nickel alloy clad steam generator tubesheets, cracking is managed by the Water Chemistry Control - Primary and Secondary and Steam Generator Integrity Programs. OAGI0000965_00011

In LRA Section 2 31 4. the applicant described that the Unit 2 replacement Westinghouse Mode! 44 steam generator tubes are fabricated from A!!oy 600TT and the Unit 3 replacement \lVestinghouse Model 44 steam generator tubes are fabricated from A!loy 690TT The applicant also described that the tubesheet surfaces in contact \Vith reactor coolant are clad vvith !ncone!, and the tube*to-tubesheet joints are vvelded. iSSUE Unless the NRC nas approved a redefinition of the pressure boundary in which the autogenous tube-to-tubesheet weld is no longer Included, or the tubesheet cladding and welds are not susceptible to PWSCC, the staff considers that the effectiveness of the primary water chemistry program should be verified to ensure PWSCC cracking is not occurring. Moreover, it is not clear to the staff how the Steam Generator Integrity Program will be able to manage PWSCC of the tubesheet cladding, including the tube-to-tubesheet welds. REQUEST 1a. For Unit 2 SGs, clarify whether the tube-to-tubesheet welds are included in the RCPB or alternate repair criteria have been permanently approved. 1b. !f the SGs do not have permanent!y approved alternate repair criteria, justify hovJ your Steam Generator Integrity Program is capable to manage PVVSCC in tube-to-tubesheet welds, or provide a plant-specific AMP that will complement the primary water chemistry program, in order to verify the effectiveness of the primary water chemistry program and ensure thai cracking due io PWSCC is noi occurring in iube-io-iubesheei weids.

2. For Unit 3 SGs tube-to-tubesheet welds, justify hOw your Steam Generator integrity Program is capable to manage PWSCC in tube-to-tubesheet welds, or provide either a plant-specific AMP that will complement the primary water chemistry program, in order to verify the effectiveness of the primary water chemistry program and ensure that cracking due to PWSCC is not occurrinQ in tube-to-tubesheet welds, or a rationale for why such a program is not needed.

RA! RC!':-3 BACKGROUND In LRA Section 4.3.3 and Commitment 33 (as amended by the letter dated January 22, 2008) the applicant discussed the methodology used to determine the locations that required environmentally-assisted fatigue analyses consistent with NUREG/CR-6260, "Application of NUREGiCR-5999 interim Fatigue Curves io Selected Nuclear Power Pi ani Components." The staff recognized ihai, in LRA Tabies 4.3-i3 and 4.3-i4, there are eight piani-specific iocaiions listed based on the six generic components identified in NU REGiCR-6260. The applicant also discussed in LRA Tables 4.3-13 and 4.3-14 that the surge line nozzle in the RCS piping is bounded by the surge line piping to safe end weld at the pressurizer nozzle. LRA Section 4.3.3 and Commitment 33 were amended as follow: OAGI0000965_00012

At least 2 years prior to entering the period of extended operation, for the locations identified in LRA Table 4.3-13 (IP2) and LRA Table 4.3-14 (IP3), under the Fatigue Monitoring Program, !P2 and !P3, !PEC wm implement one or more of the fo!!owing: (1) Consistent with the Fatigue Monltoiing Progiam, Detection of Aging Effects, update the fatigue usage calculations using refined fatigue analyses to determine valid CUFs less than 1.0 when accounting for the effects oi reactor water environment This inciudes applying the appropriate Fen factors to valid CUFs determined in accordance with one of the following. For locations in LRA Table 4.3-13 (IP2) and LRA Table 4.3-14 (IP3) with existing fatigue analysis valid for the period of extended operation, use the existing CUF. More plant-specific limiting locations with a valid CUF may be evaluated. In particular, the pressurizer lower shell will be reviewed to ensure the surge nozzle remains the limiting component Representative CUF values from other plants, adjusted to or enveloping the !PEC plant-specific extern a! !cads may be used if demonstrated applicable to IPEC. An analysis using an NRC-approved version of the ASME code or NRC-approved alternative (e.g., NRC-approved code case) may be performed to determine a vaiid CUF. ISSUE GALL AMP X.M1 states the impact of the reactor coolant environment on a sample of critical components should include the locations identified in NUREG/CR-6260, as a minimum, and that additional locations may be needed. The staff identified two concerns regarding the applicant's environmentally-assisted fatigue analyses. First, item (1) above LRA section and Commitment 33 indicated that more limiting plant-specific locations may be evaluated. However, it is only one of the options that may be taken Furthermore, the limiting locations may be added and the staff is concerned whether the applicant !s committed to verify that the plant-specific locations per NUREG/CR-6260 are bounding for the generic NUREG/CR-6260 components. Second! the staff noted that the applicant's p!ant=specific configuration may contain locations that should be analyzed for the effects of reactor coolant environment, that are more limiting than those identified in NUREG/CR-6260. This may include locations that aie limiting Oi bounding foi a particular plant-specific configuration or that have calculated CUF vaiues that are greater when compared to the iocaiions identified in NUREGiCR-6260. OAGI0000965_00013

REQUEST 1~ Confirm and justify that the plant-specific locations listed in LRA Tables 4 3-13 and 4.3-14 are bounding for the generic NUREG/CR-6260 components.

2. Confirm and justify that the locations selected for environmentally-assisted fatigue analyses in LRA Tables 4.3-13 and 4.3-14 consist of the most limiting locations foithe plant (beyond the generic components identiiied in the NUREG/CR-6260 guidance). If these iocations are not bounding, ciarify which iocations require an environmeniaiiy-assisied fatigue anaiysis and ihe actions ihai wiii be taken for ihese additional locations. if the limiting iocations identified consist of nickei aiioy, state whether the methodology used to perform environmentaiiy-assisted fatigue caicuiation for nickel alloy is consistent with NUREG/CR-6909. If not, justify the method chosen.

OAGI0000965_00014

Vice President, Operations Entergy Nuclear Operations, Inc. Indian Point Energy Center 450 Broadway, GSB P.O. Box249 Buchanan, NY 10511-0249

SUBJECT:

REQUEST FOR ADDITIONAL INFORMATION FOR THE REVIEW OF THE INDIAN POINT NUCLEAR GENER.~.T!NG UN!T NUMBERS 2 AND 3, LICENSE RENEVJAL APPLICATION

Dear Sir or Madam:

By letter dated April 23,2007, as supplemented by letters daied May 3, 2007, and june 21, 2007. Entergy Nuclear Operations, inc., (Entergy) submitted an application pursuant to Title iO of the Code of Federal Regulations Part 54, to renew the operating licenses for Indian Point Nuclear Generating Unit Nos. 2 and 3, for review by the U.S. Nuclear Regulatory Commission (NRC or the staff). The staff documented its findings in the Safety Evaluation Report Related to the License Renewal of Indian Point Nuclear Generating Unit Nos. 2 and 3 which was issued in August 2009. Since the issuance of the safety evaluation report, the staff has identified the need for additional information with respect to certain aging management programs based on lessons learned from past LRAs and recent industry operating experience. Additionally, the staff has identified issues that need additional clarification for the license renewal application. Therefore, the staff requests additional information as described in the enclosure. 

!tems in the enclosure 'lVere discussed \*vith Mr. Rebert 'lVa!po!e, and a mutua!!y agreeable date for the response is vvithin 45 days from the date of this letter. If you have any questions, please contact me at 301-415-1627, Oi via e-mail at Kimberly.Green©nrc.gov.

Sincerely, IRA/ Kimberly J. Green, Safety Project Manager Projects Branch 2 Division of License Renewal Office of Nuclear Reactor Regulation Docket Nos. 50-247 and 50-286

Enclosure:

As stated cc w/encl: Distribution via Listserv DiSTRiBUTiON: see next page ADAMS Accession Number. ML110190809 ' OFFICE I LA: DLR I PM: DLRIRPB2 I BC DLR/RPB2 I PM: DLR/RPB2 1 YEdmonds 1 KGreen 1 DVVrona 1 KGreen DATE I 01/07/2011 1 o210712o11 1 0211 012011 1 o211012o11 OFF!C!AL RECORD COPY OAGI0000965_00015

letter to the Vice President of Operations from Kimberly J. Green dated February 10, 2011

SUBJECT:

REQUEST FOR ADDITIONAL INFORMATION FOR THE REVIEW OF THE INDIAN POINT NUCLEAR GENERATING UNIT NUMBERS 2 AND 3, LICENSE RENEWAL APPLICATION D!STR!BUT!ON: HARDCOPY: DLR R/F E.. MAIL: PUBLiC [or NON-PUBLiC, if applicabie] RidsNrrDir Resource RidsNrrDirRpb*i Resource RidsNrrDirRpb2 Resource RidsNrrDirRarb Resource RidsNrrDirRasb Resource RidsNrrDirRapb Resource RidsNrrDirRerb Resource RidsNrrDirRpob Resource RidsOgcMaiiCenter Resource EDacus, OCA PCata!do, R! GMeyer, Rl NMcNamara, R! KGreen BVtJe!!ing, R! lc.,stuyvenberg ADias, RARB RConte, Rl OAvegbusi, Rl JBoska MCatts, Rl iviKowai PCataidot Ri STurk, OGC MHaiier, Ri SBurneii, OPA DJackson, Rl DMclntyre, OPA BMizuno, OGC DScrenci, Rl OPA NSheehan, Rl OPA SBurnell, OPA OAGI0000965_00016}}

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