ML15110A342

Fermi, Unit 2, Response to NRC Request for Additional Information for the Review of the License Renewal Application - Sets 23, 24, and 26

ML15110A342
Person / Time
Site:	Fermi
Issue date:	04/10/2015
From:	Kaminskas V A DTE Energy
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
NRC-15-0031
Download: ML15110A342 (37)

Text

Vito A. Kaminskas Site Vice President DTE Energy Company6400 N. Dixie Highway,

Newport, MI 48166Tel: 734.586.6515 Fax: 734.586.4172 Email: kaminskasv@dteenergy.com 4Dl-rDTE Energy-10 CFR 54April 10, 2015NRC-15-0031 U. S. Nuclear Regulatory Commission Attention:

Document Control DeskWashington D C 20555-0001

References:

1) Fermi 2NRC Docket No. 50-341NRC License No. NPF-432) DTE Electric Company Letter to NRC, "Fermi 2 License RenewalApplication,"

NRC-14-0028, dated April 24, 2014 (ML1412 1A554)3) NRC Letter, "Requests for Additional Information for the Review of theFermi 2 License Renewal Application

-Set 23 (TAC No. MF4222),"

dated March 13, 2015 (ML15051A420)

4) NRC Letter, "Requests for Additional Information for the Review of theFermi 2 License Renewal Application

-Set 24 (TAC No. MF4222),"

dated March 11, 2015 (ML 15051 A317)5) NRC Letter, "Requests for Additional Information for the Review of theFermi 2 License Renewal Application

-Set 26 (TAC No. MF4222),"

dated March 13, 2015 (ML15062A336)

6) DTE Electric Company Letter to NRC, "Response to NRC Request forAdditional Information for the Review of the Fermi 2 License RenewalApplication

-Set 15," NRC- 15-0009, dated January 15, 2015(ML15016A063)

7) DTE Electric Company Letter to NRC, "Response to NRC Request forAdditional Information for the Review of the Fermi 2 License RenewalApplication

-Set 16," NRC-15-0010, dated February 5, 2015(ML15037A531)

Subject:

Response to NRC Request for Additional Information for theReview of the Fermi 2 License Renewal Application

-Sets 23, 24, and 26 USNRCNRC- 15-0031Page 2In Reference 2, DTE Electric Company (DTE) submitted the License RenewalApplication (LRA) for Fermi 2. In References 3, 4, and 5, NRC staff requested additional information regarding the Fermi 2 LRA. Enclosure 1 to this letter provides theDTE response to the requests for additional information (RAIs). Enclosure 2 to this letterprovides revised responses to RAIs as discussed with the NRC during clarification callson March 5 and 6, 2015. The revised responses are for RAIs 2.4.4-2 and 4.1-1,previously submitted in References 6 and 7, respectively.

One new commitment is being made in this submittal.

The new commitment is in LRATable A.4 Item 14, Fire Water System, as indicated in the response to RAI B.1.19-2a inEnclosure

1. In addition, revisions have been made to commitments previously identified in the LRA. The revised commitments are in LRA Table A.4 Item 3, Aboveground Metallic Tanks, as indicated in the response to RAI B.1.1-Ia in Enclosure 1, and in LRATable A.4 Item 14, Fire Water System, as indicated in the response to RAI B.1.19-8a inEnclosure 1.Should you have any questions or require additional information, please contact LynneGoodman at 734-586-1205.

I declare under penalty of perjury that the foregoing is true and correct.Executed on April 10, 2015Vito A. Kam nskasSite Vice President Nuclear Generation

Enclosures:

1. DTE Response to NRC Request for Additional Information for theReview of the Fermi 2 License Renewal Application

-Sets 23, 24, and262. DTE Revised Response to NRC Request for Additional Information for the Review of the Fermi 2 License Renewal Application

-Set 15RAI 2.4.4-2 and Set 16 RAI 4.1-1cc: NRC Project ManagerNRC License Renewal Project ManagerNRC Resident OfficeReactor Projects Chief, Branch 5, Region IIIRegional Administrator, Region IIIMichigan Public Service Commission, Regulated Energy Division (kindschl@michigan.gov)

Enclosure 1 toNRC-15-0031 Fermi 2 NRC Docket No. 50-341Operating License No. NPF-43DTE Response to NRC Request for Additional Information for theReview of the Fermi 2 License Renewal Application

-Sets 23, 24, and 26 Enclosure 1 toNRC- 15-0031Page 1Set 23 RAI B.1.I-laBackground In request for additional information (RAI) B. 1.1-1 dated December 17, 2014, the staff requested that DTE Electric state how the aging effects of loss of material and cracking of the aluminum inthe proximity of the interface between the condensate storage tank (CST) and its concretefoundation will be managed during the period of extended operation.

In its response dated January 20, 2015, DTE Electric stated that the insulation on the CSTprevents access to the inteiface between the tank and its concrete foundation and is expected toprevent the intrusion of water and moisture.

License Renewal Application (LRA) Sections A. 1.1,A4, and B. 1.1 were revised to perform a volumetric examination consisting offour 1-footsections of the tank/concrete interface prior to entering the period of extended operation.

TheRAI response also stated that although caulking was not included in the design and installation specifications for the CST there appears to be caulking present at some locations along thetank/concrete interface.

IssueThe RAI response did not provide a basis for why it is expected that the insulation will preventaccess to the tank/concrete interface and prevent loss of material from occurring during theperiod of extended operation.

It is unclear to the staff how the configuration of the tank andinsulation preclude the possibility of water and moisture intrusion in the outdoorenvironment/weather.

If the interface is not appropriately protected from water and moistureintrusion the partially present caulk may potentially act to trap moisture that has intruded.

If aone-time volumetric examination is conducted to demonstrate that aging effects are beingeffectively

managed, then the examination is to be of a representative area. Based on its review,the staff has concluded that four 1-foot sections do not constitute a representative sample size forthis type of inspection.

License Renewal Interim Staff Guidance (LR-ISG)-2012-02, "AgingManagement of Internal

Surfaces, Fire Water Systems, Atmospheric Storage Tanks, andCorrosion Under Insulation, "Aging Management Program (AMP) XI.M29, "Aboveground Metallic Tanks, "provides examples of representative sample sizes.Request1. If the tank insulation is being credited as a moisture barrier or preventive

measure, providethe basis andjustification for why it is expected that the insulation on the CST will preventthe access of water and moisture to the tank/concrete inteiface and is an appropriate preventive action to manage loss of material during the period of extended operation.

Theresponse should include:0 the intended function of the insulation on the CST Enclosure 1 toNRC- 15-0031Page 2* a physical description or drawing of the insulation relative to the tank/concrete interface.

The level of detail in the description should provide for an understanding of how theconfiguration of the tank and insulation preclude the possibility of water and moistureintrusion in the outdoor environment/weather.

The description should include relevantdimensions.

This description is only needed if the tank insulation is being credited as apreventive measure against loss of material at the tank/concrete intetface.

• an estimate (both total length and percentage) of how much of the tank/concrete interface has the preexisting caulking present to potentially entrap water and moisture.

Clarify ifthe caulking will remain in a partially present condition during the period of extendedoperation.

• if caulking is credited as a preventive

measure, clarify if it will be inspected consistent with Generic Aging Lessons Learned (GALL) Report AMP XI.M29, as modified by LR-ISG-2012-02.

2. If the one-time volumetric inspection is being performed to demonstrate the effectiveness ofthe insulation in preventing moisture intrusion at the tank/concrete interface, instead ofestablishing the general condition of the tank prior to entering the period of extendedoperation, state and justify the basis used to determine that four 1 foot sections of thetank/concrete interface is a representative sample. If an alternate inspection is being used tomanage the loss of material in the proximity of the tank/concrete interface, provide the basisand justification for the inspection method, extent of inspection, andfiequency of inspection.

Response

1. The condensate storage tank (CST) insulation and caulking is not credited as a moisturebarrier.

As discussed in the Updated Final Safety Analysis Report (UFSAR) Section 9.2.6,corrosion resistance of the tank is achieved through the use of a high-strength aluminumalloy (grade 5454).2. External inspection is not sufficient to assess the condition of the tank bottom interface withthe concrete support structure for loss of material.

Therefore, an alternate inspection will beused to manage the loss of material in the proximity of the tank/concrete interface as follows.Inspection of the tank bottom/concrete interface zone will be performed using volumetric techniques from inside the tank. This inspection will be conducted once in the ten-yearperiod prior to the period of extended operation and every ten years thereafter in accordance with the frequency recommended in NUREG-1801 Section XI.M29 Aboveground MetallicTanks for tank bottoms.

A minimum of 25% of this interface surface will be examined.

Thevolumetric inspection will be on a 2" grid or less, depending on the technology utilized.

Further, the inspection of the concrete/tank bottom interface zone will be in addition to thatrequired by the GALL for a general tank bottom volumetric inspection.

Loss of material is the aging effect being managed.

Inspection for cracking is not necessary Enclosure 1 toNRC- 15-0031Page 3as cracking is not an aging effect requiring management for aluminum alloy 5454.Aluminum alloy 5454, since it contains less than 12% zinc, less than 6% magnesium, andless than 1% copper, is not susceptible to cracking per EPRI 1010639 "Non Class IMechanical Implementation Guide and Mechanical Tools" Appendix D, Table 4-1 (airenvironment) and Appendix B, Table 4-3 (raw water environment).

LRA Revisions:

LRA Tables 3.4.1 and 3.4.2-1 and LRA Sections A.1.1, A.4, and B.1.1 are revised as shown onthe following pages. Additions are shown in underline and deletions are shown in strike-through.

Note that previous changes to these same LRA sections made in the July 30, 2014 letter(NRC-14-0051) and January 20, 2015 letter (NRC-15-0005) are not shown in underline or strike-through such that only the new changes due to RAI B. 1.1-1 a are shown as revisions.

Enclosure 1 toNRC-15-0031 Page 4Table 3.4.1Summary of Aging Management Programs for the Steam and Power Conversion SystemEvaluated in Chapter VIII of NUREG-1801 Table 3.4.1: Steam and Power Conversion SystemsAgingItem Aging Effect/ Management Further Evaluation Number Component Mechanism Programs Recommended Discussion 3.4.1-31 Stainless steel, Loss of material Chapter XI.M29, No Consistent with NUREG-aluminum tanks due to pitting, and "Aboveground 1801. Loss of material-aad (within the scope crevice corrosion; Metallic Tanks" ..aeki..g for aluminumof Chapter cracking due to tanks exposed to outdoorXI.M29, stress corrosion air, concrete or soil is"Aboveground cracking managed by theMetallic Tanks") Aboveground Metallicexposed to soil Tanks Program.

Crackingq or concrete, or is not an aqingq effectthe following requiring management forexternal aluminum tanks with lowenvironments zinc, magnesium, andair-outdoor, air- copper content.

There areindoor no stainless steel tanksuncontrolled, (consistent with the scopemoist air, of NUREG-1801, Chaptercondensation XI.M29, "Aboveground Metallic Tanks") in thesteam and powerconversion systems.I Enclosure 1 toNRC- 15-0031Page 5Table 3.4.1: Steam and Power Conversion SystemsAgingItem Aging Effect/ Management Further Evaluation Number Component Mechanism Programs Recommended Discussion 3.4.1-63 Insulated steel, Loss of material Chapter XI.M36, No Consistent with NUREG-stainless steel, due to general "External Surfaces 1801. Loss of material forcopper alloy, (steel, and copper Monitoring of steel insulated pipingaluminum, or alloy), pitting, or Mechanical components exposed tocopper alloy (> crevice corrosion, Components" or condensation is managed15% Zn) piping, and cracking due to Chapter XI.M29, by the External Surfacespiping stress corrosion "Aboveground Monitoring Program.

Losscomponents, cracking Metallic Tanks" (for of material and raek4i.g ofand tanks (aluminum, tanks only) aluminum insulated tanksexposed to stainless steel and exposed to outdoor air iscondensation, copper alloy (> 15% maintained by theair-outdoor Zn) only) Aboveground MetallicTanks Program.

Crackingis not an a-ging effectrequiring management foraluminum tanks with lowzinc, magnesium, andcopper content.I Enclosure 1 toNRC- 15-0031Page 6Table 3.4.2-1Condensate Storage and Transfer SystemSummary of Aging Management Evaluation Table 3.4.2-1:

Condensate Storage and Transfer SystemAging Effect AgingComponent Intended Requiring Management NUREG- Table 1Type Function Material Environment Management Programs 1801 Item Item Notesinsulated Pressue -m AA---eutdee Aae-d V111 r= 2-402- 1-tan* be d..,w y Metal" 63TanksIInsulated Pressure Aluminum Air -outdoor Loss of material Aboveground VIII.E.S-402 3.4.1- A, 404tank boundary (ext) Metallic 63Tanks Enclosure 1 toNRC-15-0031 Page 7A.1.1 Above-ground Metallic Tanks ProgramThe Aboveground Metallic Tanks Program is a new program that will manage loss of materialand cracking for outdoor tanks within the scope of license renewal that are sited on soil orconcrete.

Preventive measures to mitigate corrosion and cracking were applied duringconstruction, such as using the appropriate materials, protective

coatings, and elevation asspecified in design and installation specifications.

For the painted carbon steel combustion turbine generator (CTG) fuel oil tank, the program will monitor the external surface condition forindications and precursors of loss of material.

For the insulated aluminum condensate storagetank (CST), the program will monitor the condition of a representative sample of the tankexternal surface for signs of loss of material.R-".

k, ,,;,g, using visual inspections and surfaceexaminations.

Exterior portions of the tanks will be inspected in accordance with Table 4a,"Tank Inspection Recommendations,"

identified in LR-ISG-2012-02.

There are no indoor tanksincluded in this program.CST internal inspections will be conducted in accordance with Table 4a, identified above.Internal inspections of the CTG fuel oil tank will be conducted in accordance with NUREG-1801, XI.M30.This program will also manage the bottom surfaces of both in-scope aboveground metallictanks, which are on concrete ring foundations and sand. The program will require ultrasonic testing (UT) of the tank bottoms to assess the thickness against the thickness specified in thedesign specification.

UT of the tank bottoms will be performed whenever the tanks are drainedor at intervals not less than those recommended in Table 4a during the period of extendedoperation.

Caulking or sealant at the concrete/tank interfaces is not credited in the installation and design specifications.

Within tho t8 en F oasprior to the prio~d Of oxtondod oporation, a V8olumeWRic xAminaRRRtion of fourI1 fot octOnof tho intorfaco botWoon tho CST-4 AnRd cencRoFto ring foundation Will bo performned for. cr-acking and toss of m~atorial.

If crackin~g and loss Of materal WAr not present, this programwil coduct subsequent npciOnof the exterior SUrface Of the nuatn.Whitetn years prior to the period of extended operation and every ten years thereafter, a volumetric examination of a minimum 25% of the CST tank bottom interface with the concrete ringfoundation will be performed to manage loss of material.

The volumetric inspection will be on a2" grid or less, depending on the technology utilized.

This program will be implemented prior to the period of extended operation, with initialinspections within the ten years prior to the period of extended operation.

Enclosure I toNRC-15-0031 Page 8A.4 LICENSE RENEWAL COMMITMENT LISTNo. Program or Activity Commitment Implementation Source____ ___ ___ ___ __ _ ___ ___ ___ ____ ___ ___ ___ ____ ___ ___ ___ ___ Schedule

_ _ _ _3 Aboveground Metallic Implement new Aboveground Metallic Tanks Program that will Prior to A.1.1Tanks manage loss of material and cracking for outdoor tanks within September 20,the scope of license renewal that are sited on soil or concrete.

2024, or the endCST internal inspections will be conducted in accordance with of the lastTable 4a of LR-ISG-2012-02; internal inspections of the CTG refueling outagefuel oil tank will be conducted in accordance with NUREG-1 801, prior to March 20,XI.M30. This program will also manage the bottom surfaces of 2025, whichever both in-scope aboveground metallic tanks. Within tho ton y.a.. is later. Initialprior to po-iod Of -WeRe-d .p..ati..,

a oIUm..t.ric inspections will beexam natien of fouJr 1 foot oct!ncn of tho nto,-fAco b8t'e-n tho performed withinCST and- concrete ring foun_,.d.ation

.ill be for c.Ra.kiff the ten years priorand lo, s Of If crakig and ..oS of material aro not to March 20,pr....t, this

'i conduct " '" n. -ubeunt incpoctions of th2 025.of inulatonR.

Within the ten years prior tothe period of extended operation and every ten years thereafter, a volumetric examination of a minimum 25% of the CST tankbottom interface with the concrete ring foundation will beperformed to manage loss of material.

The volumetric inspection will be on a 2" grid or less, depending on thetechnology utilized.

Enclosure 1 toNRC- 15-0031Page 9B.1.1 ABOVEGROUND METALLIC TANKSProaram Description The Aboveground Metallic Tanks Program is a new program that will manage loss of materialand cracking for outdoor tanks within the scope of license renewal that are sited on soil orconcrete.

Preventive measures to mitigate corrosion and cracking were applied duringconstruction, such as using the appropriate materials, protective

coatings, and elevation asspecified in design and installation specifications.

For the painted carbon steel combustion turbine generator (CTG) fuel oil tank, the program will monitor the external surface condition forindications and precursors of loss of material.

For the insulated aluminum condensate storagetank (CST), the program will monitor the condition of a representative sample of the tankexternal surface for signs of loss of material-a

..Faeki. , using visual inspections and surfaceexaminations.

Exterior portions of the tanks will be inspected in accordance with Table 4a,"Tank Inspection Recommendations,"

identified in LR-ISG-2012-02.

There are no indoor tanksincluded in this program.CST internal inspections will be conducted in accordance with Table 4a, identified above.Internal inspections of the CTG fuel oil tank will be conducted in accordance with NUREG-1801, XI.M30.This program will also manage the bottom surfaces of both in-scope aboveground metallictanks, which are on concrete ring foundations and sand. The program will require ultrasonic testing (UT) of the tank bottoms to assess the thickness against the thickness specified in thedesign specification.

The UT testing of the tank bottoms will be performed whenever the tanksare drained or at intervals not less than those recommended in Table 4a during the period ofextended operation.

Caulking or sealant at the concrete/tank interfaces is not credited in theinstallation and design specifications.the tsn ;,,,arg mroer to tht nor;ed of arprnton;

a of fou -r1 foot sectionseof the intofaco between the CST- andWconcete ringfoundation will be perform~ed for- crFac~kin and Iersi of Material.

if cracking

-;nd- Iesw of material Wre not precent, thic programAwill conduct subsequent incpectioens of the Aoxtorior surfaco of the inculation-.Within the tenvears prior to the period of extended operation and every ten vears thereafter, a volumetric examination of a minimum 25% of the CST tank bottom interface with the concrete rinqfoundation will be performed to manage loss of material.

The volumetric inspection will be on a2" grid or less, depending on the technology utilized.

This program will be implemented prior to the period of extended operation, with initialinspections within the ten years prior to the period of extended operation.

Enclosure 1 toNRC- 15-0031Page 10Set 24 RAIB.1.4-2a

Background

Request for Additional Information (RAI) B. 1.4-2 requested the basis for why a 100 m Vpolarization acceptance criterion will provide adequate protection for buried steel piping in amixed metal environment.

The response dated January 15, 2015, states that:If the new program, when developed, allows use of the -100 m V criterion for pipingwithin the scope of the Buried and Underground Piping AMP, then the program willaddress why the effects of mixed potentials are minimal and why the most anodic metal ina system for which this criteria is used is adequately protected as required by Note 2 ofTable 6a of GALL Report AMP XI.M41 as modified by LR-ISG-2011-03.

License Renewal Interim Staff Guidance (LR-ISG)-2011-03, "Changes to the Generic AgingLessons Learned (GALL) Report Revision 2 Aging Management Program XI.M41, 'Buried andUnderground Piping and Tanks, "' Table 6a, "Cathodic Protection Acceptance

Criteria, "footnote 2 states that, "applicants must explain in the application why the effects of mixedpotentials are minimal and why the most anodic metal in the system is adequately protected."

IssueGiven that the basis for use of the 100 inV polarization acceptance criterion was not provided inthe application or response to RAI B. 1.4-2, the staff cannot complete its evaluation of the"acceptance criteria "program element.RequestState the basis for why the effects of mixed potentials will be minimal and why the most anodicmetal in the system will be adequately protected if the 100 mV polarization cathodic protection acceptance criterion is used.Response:

The basis for why the effects of mixed potentials will be minimal and why the most anodic metalin the system will be adequately protected if the 100 mV polarization cathodic protection acceptance criterion is used is as follows.

In performing cathodic protection

surveys, the -850mV polarized potential criterion specified in National Association of Corrosion Engineers (NACE) SP0169-2013 for steel piping will be the primary acceptance criterion to determine cathodic protection (CP) system effectiveness.

Alternately, as specified in NACE SP0169-2013 for steel piping (Section 6.2.1), the following criteria can be used to demonstrate cathodicprotection effectiveness:

Enclosure 1 toNRC- 15-0031Page 111 -1 OOmV or greater cathodic polarization; 2 -Any empirically verified criteria that has been shown to be effective (e.g. corrosion rate).When either of the alternate criteria is applied, electrical resistance probes (ERPs) will beinstalled in select locations as determined by a Cathodic Protection Specialist.

The ERPs will bemade of the most anodic metal in the system to ensure adequate protection of the most anodicsystem metal. The ERPs provide for measurements that can be used to demonstrate CPeffectiveness in controlling the corrosion rate. Based on these measurements, the level of CP canbe adjusted to reduce the corrosion rate to acceptable levels. Concurrent with the ERPs,permanent reference cells and reference metal will be installed.

Installation of the permanent reference cells at pipe depth and near the piping of interest will allow for an accuratemeasurement of pipe-to-soil potential, minimizing the influence of mixed metals. The reference metals will allow both instant-off (polarized metal) and native readings to be obtained for aparticular portion of piping without the necessity of interrupting or powering down the rectifiers.

This information can be used either concurrently with, or in place of the measured corrosion ratefrom the ERPs to determine if criteria I and 2 above are met.An upper limit of -1200 mV for pipe-to-soil potential measurements of coated pipes will also beestablished, so as to preclude potential damage to coatings.

If the -850 mV instant-off criterion is not met, the following acceptance criteria can be used toassess cathodic protection effectiveness during the annual surveys:" A measured corrosion rate from the soil corrosion probes of I mil per year (mpy) orless will demonstrate that the cathodic protection system has provided effective protection for that surveillance year and no further evaluation is necessary.

The loss ofmaterial rate will be established based on the past 1 year of measurements taken on asemi-annual frequency in conjunction with rectifier readings.

• If the measured corrosion rate for the given surveillance year exceeds 1 mpy, thecorrosion rate will be used as an input into a remaining life calculation for thecomponent.

If the measured corrosion rate indicates that the remaining life of the pipeexceeds the life of the plant, it will be concluded that the cathodic protection system hasbeen effective in mitigating significant corrosion for that surveillance year at thelocation of interest.

• If the observed corrosion rates from the probes, over the given surveillance year, do notsupport the conclusion that the intended function of the component would bemaintained through the period of extended operation, it will be concluded that thecathodic protection system has not been effective over the surveillance interval.

Themeasurements will count against the cathodic protection effectiveness determinations performed in accordance with LR-ISG-2011-03, Table 4a, footnote 2.c.iii.EPRI document 3002005067, "Evaluation for Installing or Upgrading Cathodic Protection Systems,"

describes two methods for determining service life. Both predict service life based on Enclosure 1 toNRC- 15-0031Page 12design margin and established corrosion rates. One uses the difference between nominal andminimum wall thickness in conjunction with the measured corrosion rate to predict service life.The other uses the difference between measured and minimum wall thickness to predictremaining service life. Either method may be used.Additionally, DTE will review minimum wall calculations for in-scope piping for whichcorrosion rates will be used, and for piping segments without pre-existing minimum wallcalculations, a comparison of critical piping characteristics (e.g., piping specifications, systemdesign information, pipe diameter) will be performed.

These calculations and comparisons would demonstrate that considering all design loads (i.e. hoop stresses, axial stress, soiloverburden) the buried in-scope piping is capable of withstanding at least 60 mils (1 mpy for 60years) of material loss from 87.5 percent of the nominal thickness.

If this review determines 60mils of material loss is not acceptable for a given portion of piping, the allowable corrosion ratewill be adjusted accordingly.

Where used, the electrical resistance probes will be uncoated and placed in the immediate vicinity of the buried piping it is representing.

For each installation application, two probes willbe installed; one connected to the cathodic protection system and one left unprotected.

The testprobe left unprotected (not connected to the pipe) will be free of the mixed metals influence.

Information provided in NACE International Publication 05107, "Report on Corrosion Probes inSoil or Concrete,"

will be considered during the application, installation, and use of soilcorrosion probes. However, the specific details on installation and use of the soil corrosion probes will be in accordance with vendor, manufacturer, and NACE-qualified cathodic protection specialist recommendations.

Soil corrosion probes will not necessarily be installed at each cathodic protection survey testpoint. Frequently, the soil corrosion probe assemblies will be installed away from cathodicprotection test points. With regard to the soil corrosion probe locations and utilization of thedata: (a) a NACE-qualified cathodic protection specialist will assist in selecting the location(s);

(b) both the soil corrosion probes and the permanent reference electrode are installed below-grade and in close proximity to the buried piping of interest; (c) a NACE-qualified cathodicprotection specialist will evaluate the difference in the respective locations between the soilcorrosion probes and the cathodic protection test point to determine whether the difference in therelative data could be reasonably attributed to other site features (e.g., exposed large surface areatank bottoms, heavily congested areas of other buried piping, very large diameter pipes); and (d)if the difference in the observed data could be attributed to adjacent site features, cathodicprotection effectiveness at the existing test point will not be evaluated by use of data from thesoil corrosion probes. Placement of soil corrosion probes will consider existing soil (e.g.moisture

content, pH and resistivity measurements) through the use of soil sampling.

LRA Revisions:

LRA Sections A.1.4 and B.1.4 are revised as shown. Additions are shown in underline anddeletions are shown in strike-through.

Enclosure I toNRC- 15-0031Page 13A.1.4 Buried and Underground Piping ProgramThe Buried and Underground Piping Program is a new program that will manage the effects ofaging on the external surfaces of buried and underground piping components within the scopeof license renewal.

The program will manage aging effects of loss of material and cracking forthe external surfaces of buried and underground piping fabricated of aluminum, carbon steel,gray cast iron, and stainless steel through preventive and mitigative measures (e.g., coatings, backfill

quality, and cathodic protection) and periodic inspection activities during opportunistic ordirected excavations.

There are no underground or buried tanks for which aging effects wouldbe managed by the Buried and Underground Piping Program.

Fermi 2 utilizes a cathodicprotection system. Fermi 2 has performed preliminary laboratory soil composition analyses onsamples removed from the site to evaluate the potential corrosivity of the soil for use in life cyclemanagement.

Soil testing will be conducted once in each ten-year period starting ten years prior to the periodof extended operation, if a reduction in the number of inspections recommended in Table 4a ofNUREG-1801, XI.M41, is taken based on a lack of soil corrosivity.

If the 100 mV criterion is applied for cathodic protection for specific piping, electric resistance probes (ERPs) will be installed in select locations as determined by a Cathodic Protection Specialist.

The ERPs will be made of the most anodic metal in the system to ensure adequateprotection of the most anodic system metal. Concurrent with the ERPs, permanent reference cells and reference metal will be installed.

Installation of the permanent reference cells at pipedepth and near the piping of interest will allow for an accurate measurement of pipe-to-soil potential, minimizing the influence of mixed metals. Where used, the electrical resistance probes will be uncoated and placed in the immediate vicinity of the buried piping it isrepresenting.

For each installation application, two probes will be installed:

one connected tothe cathodic protection system and one left unprotected.

The test Drobe left unprotected (notconnected to the pipe) will be free of the mixed metals influence.

This program will be implemented prior to the period of extended operation.

Enclosure 1 toNRC- 15-0031Page 14B.1.4 BURIED AND UNDERGROUND PIPINGProgram Description The Buried and Underground Piping Program is a new program that will manage the effects ofaging on the external surfaces of buried and underground piping within the scope of licenserenewal.

The program will manage aging effects of loss of material and cracking for theexternal surfaces of buried and underground piping fabricated of aluminum, carbon steel, graycast iron, and stainless steel through preventive and mitigative measures (e.g., coatings, backfillquality, and cathodic protection) and periodic inspection activities during opportunistic ordirected excavations.

There are no underground or buried tanks for which aging effects wouldbe managed by the Buried and Underground Piping Program.

Fermi 2 utilizes a cathodicprotection system. Fermi 2 has performed preliminary laboratory soil composition analyses onsamples removed from the site to evaluate the potential corrosivity of the soil for use in life cyclemanagement.

Soil testing will be conducted once in each ten-year period starting ten years prior to the periodof extended operation, if a reduction in the number of inspections recommended in Table 4a ofNUREG-1801,Section XI.M41 is taken based on a lack of soil corrosivity.

If the 100 mV criterion is applied for cathodic protection for specific piping, electric resistance probes (ERPs) will be installed in select locations as determined by a Cathodic Protection Specialist.

The ERPs will be made of the most anodic metal in the system to ensure adequateprotection of the most anodic system metal. Concurrent with the ERPs, permanent reference cells and reference metal will be installed.

Installation of the permanent reference cells at pipedepth and near the piping of interest will allow for an accurate measurement of pipe-to-soil potential, minimizing the influence of mixed metals. Where used, the electrical resistance probes will be uncoated and placed in the immediate vicinity of the buried piping it isrepresenting.

For each installation application, two probes will be installed:

one connected tothe cathodic protection system and one left unprotected.

The test probe left unprotected (notconnected to the pipe) will be free of the mixed metals influence.

This program will be implemented prior to the period of extended operation.

Enclosure 1 toNRC-15-0031 Page 15Set 24 RAIB.I.19-2a

Background

By letter dated December 17, 2014, the staff issued RAI B. 1.19-2 requesting the basis for whythere is reasonable assurance that the intended function of the deluge systems for the controlcenter HVAC (heating, ventilation, and air conditioning) make-up filter charcoalfilter absorberunit and the control center HVAC recirculation filter charcoal absorber unit will be met duringthe period of extended operation when their piping and nozzle inspections only occur when thecharcoal media is replaced.

During the audit, the staff reviewed charcoal filter mediareplacement work orders and determined that the media is replaced approximately every 7 to 10years.The response dated January 15, 2015, provides a basis for why the stainless steel piping exposedto the air environment downstream of the manual closed isolation valves fiom the fire watersystem would not be susceptible to flow blockage from that portion of the piping. The responsealso states that the piping upstream of the manual isolation valves is constructed of carbon steeland "is routinely flushed to ensure no blockage."

IssueFlow blockage due to buildup of corrosion products would not be expected to occur in thestainless steel, normally-dry portions of the charcoal filter water distribution piping. However,corrosion products could accumulate in the upstream carbon steel piping and, although the RAIresponse states that this piping is routinely

flushed, it did not state the periodicity of theseflushes.

The staff lacks sufficient information to conclude that corrosion product debris will notprevent the fire water distribution piping from performing its intended function during the periodof extended operation.

RequestState andjustify the periodicity of and the method of flushing the carbon steel piping upstreamof the control center HVAC make-up filter charcoal filter absorber unit and control centerHVAC recirculation filter charcoal absorber unit; and state how the periodicity of the flushing isdocumented.

Response

The carbon steel fire protection water supply leading to the CCHVAC makeup and recirculation units is normally drained.

The isolation valve directly feeding this section of piping is lockedclosed. In accordance with the Technical Requirements Manual (TRM) surveillance requirements this isolation valve is cycled open and closed once every 12 months. Following closure of the isolation valve the downstream piping is drained.

During draining, DTE personnel Enclosure 1 toNRC- 15-0031Page 16inspect for particulates and other indications of flow blockage.

However, the valve operability test procedure does not require documentation of this inspection.

Therefore, the Fire Water System Program will be enhanced to revise the valve operability testprocedure to include formal documentation of the drain down inspection for indications of flowblockage.

As addressed in the enhancement in the response to RAI B.1.19-6 (DTE letterNRC- 15-0002 dated January 15, 2015), if any criteria of Sections 14.2.1.3 or 14.3.1 of NFPA25-2011 are met, an obstruction investigation will be conducted.

LRA Revisions:

LRA Sections A. 1.19, A.4, and B. 1.19 are revised as shown. Additions are shown in underline and deletions are shown in strike-through.

Note that previous changes to these same LRAsections made in the July 30, 2014 letter (NRC-14-0051) and January 15, 2015 letter(NRC- 15-0002) are not shown in underline or strike-through such that only the new changes dueto RAI B.1.19-2a are shown as revisions.

Enclosure I toNRC- 15-0031Page 17A.1.19 Fire Water System ProgramThe Fire Water System Program will be enhanced as follows.* Revise Fire Water System Program procedures to include formal documentation of theCCHVAC makeup and recirculation fire water supply drain down inspection forindications of flow blockage.

Enhancements will be implemented prior to the period of extended operation.

Enclosure 1 toNRC-15-0031 Page 18A.4 LICENSE RENEWAL COMMITMENT LISTNo. Program or Activity Commitment Implementation Source____ ____ ____ __ ____ ____ ___ ____ ____ ____ ___ ____ ____ ___ Schedule

_ _ _14 Fire Water System Enhance Structures Monitoring Program as follows:

Prior to A.1.19September 20,q. Revise Fire Water System Pro-gram procedures to include 2024, or the endformal documentation of the CCHVAC makeup and of the lastrecirculation fire water supply drain down inspection for refueling outageindications of flow blockage.

prior to March 20,2025, whichever is later, with theexception that theactivities described in thiscommitment forpiping segmentsdesigned to bedry butdetermined to becollecting watershall beconducted withinfive years prior toMarch 20, 2025.

Enclosure I toNRC- 15-0031Page 19B.1.19 FIRE WATER SYSTEMEnhancements Element Affected Enhancement

4. Detection of Acqina Effects Revise Fire Water System Program procedures toinclude formal documentation of the CCHVACmakeup and recirculation fire water supply draindown inspection for indications of flow blockagie.

6. Acceptance Criteria Revise Fire Water System Program procedures toinclude acceptance criteria that any indication offouling is evaluated.

Enclosure I toNRC- 15-0031Page 20Set 24 RAI B.1.19-8a

Background

One of the plant-specific operating experience examples cited in the license renewal application (LRA) describes fire suppression flow testing that demonstrated degrading conditions in theunderground piping system. The LRA states that the frequency of testing and evaluation of thispiping has been increased from 3 years, to annual testing.The response to RAI B. 1.19-8, dated January 15, 2015, states an enhancement to the LRASection B. 1.19 "corrective action "program element.

The enhancement states, "['revise FireWater System Program procedures to consider in accordance with the Corrective ActionProgram increasing test frequency if there is a decreasing trend inflow in the fire water systemflow test."IssueThe staff recognizes that if an adverse trend in system performance is detected during the periodof extended operation, the condition adverse to quality will be evaluated in accordance with theCorrective Action Program.

However, given the existing degraded condition, the staff lackssufficient information to:" Find the enhancement acceptable because the use of the term "consider" leaves itindeterminate whether the frequency offire water system flow testing will be increased during the period of extended operation if the current decreasing trend in systemperformance reveals that the system may not be capable ofperforming its intendedfunction throughout the period of extended operation.

• Conclude that existing corrective actions will be sufficient to correct the adverse trendprior to the period of extended operation.

Therefore, the staff cannot conclude that plant-specific operating experience associated withflow testing of the underground/fire water system has been adequately evaluated.

RequestState and justify the basis for why the current trend in fire water system performance will becorrected prior to the period of extended operation.

Alternatively, revise LRA Section A. 1.1.19,as necessaty, to continue the increasedfirequency offire water system flow tests until such timeas trend data demonstrates that the system will be capable ofperforming its intended functionthroughout the period of extended operation.

Enclosure I toNRC- 15-0031Page 21Response:

DTE performs annual water flow tests per the Corrective Action Program due to anomalies inwater flow test data first observed in 2008. DTE will continue the increased frequency (i.e.annual) water flow tests until such a time as trend data from test results indicate the system willbe capable of performing its intended function throughout the period of extended operation.

Theenhancement to the Fire Water System Program made in the response to RAI B. 1.19-8 (DTEletter NRC-15-0002 dated January 15, 2015) will be revised to ensure this occurs.Once the trend data from test results indicate the system will be capable of performing itsintended function throughout the period of extended operation, DTE will resume Technical Requirements Surveillance Requirement (TRSR) 3.12.2.19 water flow test frequency of at leastonce every 3 years; exceeding the NFPA 25 Section 7.3.1 provision of once every 5 years.LRA Revisions:

LRA Sections A. 1.19, A.4, and B. 1.19 are revised as shown. Additions are shown in underline and deletions are shown in strike-through.

Note that previous changes to these same LRAsections made in the July 30, 2014 letter (NRC-14-0051) and January 15, 2015 letter(NRC-I15-0002) are not shown in underline or strike-through such that only the new changes dueto RAI B. 1.19-8a are shown as revisions.

Enclosure I toNRC- 15-0031Page 22A.1.19 Fire Water System ProgramThe Fire Water System Program will be enhanced as follows.If the decreasing trend in fire water system flow tests is not resolved through theCorrective Action Program prior to the period of extended operation, revise Revise-Fire Water System Program procedures to conisder, in arccrdanco

'.eth tho Cra.toia-ActionProFgam, in"r.a.ing test f.o.u.ncy if thoro is a doc..a..ng trond ,, flow in the continueperforming annual fire water system flow tests during the period of extended operation until such a time as trend data from fire water system flow tests indicates that the systemwill be capable of performing its intended function throughout the period of extendedoperation and therefore TRM frequency may be resumed.

Enclosure 1 toNRC- 15-0031Page 23A.4 LICENSE RENEWAL COMMITMENT LISTNo. Program or Activity Commitment Implementation Source_______________

_______________________________________

Schedule

____14 Fire Water System Enhance Structures Monitoring Program as follows:

Prior to A.1.19September 20,p. If the decreasing trend in fire water system flow tests is not 2024, or the endresolved through the Corrective Action Program prior to the of the lastperiod of extended operation, revise Revise-Fire Water refueling outageSystem Program procedures to coc.ider, in accrdanco "ith prior to March 20,the Corrc.. y Action Pr ogr.m. iR.. g tet 2025, whichever thero iA a docroQ-a.in trond *n filoW in tho continue is later, with theperforming annual fire water system flow tests during the exception that theperiod of extended operation until such a time as trend data activities from fire water system flow tests indicates that the system described in thiswill be capable of performing its intended function commitment forthroughout the period of extended operation and therefore piping segmentsTRM frequency may be resumed.

designed to bedry butdetermined to becollecting watershall beconducted withinfive years prior toMarch 20, 2025.

Enclosure I toNRC- 15-0031Page 24B.1.19 FIREWATER SYSTEMEnhancements Element Affected I Enhancement

7. Corrective Actions If the decreasing trend in fire water system flowtests is not resolved throuqh the Corrective ActionProgram prior to the period of extended operation, revise Revise-Fire Water System Programprocedures to oensider, in accordanco with theCoF~rrccti Acton Program,~con toestfrequency if there is a decocn tnd in flow4A. in thecontinue performing annual fire water system flowtests during the period of extended operation untilsuch a time as trend data from fire water systemflow tests indicates that the system will be capableof performing its intended function throughout theperiod of extended operation and therefore TRMfra "ane, n ha me"mckH________________________________________________________

j ,r..tJ~.,

• '.JY IIflAY IES~~A.

Enclosure 1 toNRC- 15-0031Page 25Set 26 RAIB.1.3-la

Background

In a letter dated January 26, 2015, the applicant provided the 2013 BADGER test report inEnclosure 2 of the submittal.

The report provides information on the condition of the Boraflexmaterial in the spent fiel pool and by extension the effectiveness of the Boraflex Monitoring Program.

The monitoring program is implemented to ensure that no unexpected degradation ofthe Boraflex material compromises the criticality analysis.

IssueThe staff reviewed the 2013 BADGER test report and has determined that more information isneeded to complete its review. The staff has concerns on whether the program providesreasonable assurance that it can detect unexpected degradation of the Boraflex material in thespent fuel pool.Request1. On page 8 of Enclosure 2 to NRC-15-0008, it states that once a critical dose level has beenattained (approximately 2x109 rads), Boraflex becomes susceptible to dissolution by water inthe spent fuel pool environment.

Please discuss what percentage o/Boraflex panels in theFermi 2 spent fuel pool has attained the critical dose level of 2xl 0 rads.2. On page 8 of Enclosure 2 to NRC-15-0008, it states that a RACKLIFE model of the Fermi 2racks is used to estimate the service history of each Boraflex panel, specifically estimated gamma exposure.

The license renewal application further states that the RACKLIFE modelis used to calculate the amount of boron carbide loss from the Boraflex panels. Pleasediscuss how the RACKLIFE model predictions compare with the results of the 2013BADGER test report.3. In the conclusion section of Enclosure 2 to NRC-15-0008, it states that the areal densities of3 of 60 panels tested (i.e., 5 percent) fell below the minimum acceptance limit of0.015656 g-'0B/cm2.These panels were subsequently taken out of service.

Please discusswhether a similar percentage of the untested panels in the spent fuel pool would be expectedto have comparable degradation and thus may not meet the acceptance limit of0. 015656 g-10B/cmn. If so, discuss how this will impact the assumptions found in thecriticality analysis.

In addition, discuss how the Boraflex Monitoring Program providesreasonable assurance that unexpected degradation of Boraflex panels in the spent fuel poolwill be identified Enclosure 1 toNRC- 15-0031Page 26Response:

1. 87% of the Boraflex panels had attained a dose level of 2.OOE+09 rads or higher at the timeof the 2013 BADGER test.2. The RACKLIFE code is a mass balance calculation of silica in the spent fuel pool (SFP).Calculated results include gamma radiation dose absorbed by Boraflex panels, pool silicaconcentrations to compare with the measured silica from plant chemistry data, and thepercentage boron-carbide lost from each panel. Hence, RACKLIFE will calculate boroncarbide loss. BADGER testing measures the state of a set of Boraflex panels at a point intime. BADGER results can be used to confirm that a SFP still meets its criticality designbasis at that point in time. A RACKLIFE projection can then be used to extrapolate theseresults into the future.When comparing

% B4C loss from RACKLIFE to minimum areal density (AD) fromBADGER there does not appear to be a correlation (refer to Figure 1 on the following page).An analysis of the BADGER 2013 data using Minitab resulted in a Pearson correlation coefficient of 0.130. The Pearson correlation coefficient can range from -1 (for a strongnegative correlation) to + 1 (for a strong positive correlation).

A value equal to zero yields nocorrelation.

Laerd Statistics (www.statistics.laerd.com) has proposed the following guidelines for interpreting the Pearson correlation coefficient:

Strength of Association Coefficient Small 0.1 -0.3Medium 0.3 -0.5Large 0.5- 1.0Hence, a correlation coefficient of 0.130 shows the strength of association to be small.

Enclosure 1 toNRC- 15-0031Page 27Figure 1:%B4C LOSS VERSUS AREAL B-10 DENSITY4Ft 3.5ACK 3LF 2.5E2C, 0.5L ISO.S[ 4%B4CLoss fromRACKLIFE]_____________________

00.0140000.0150000.016000 0.017000 0.018000Min. Areal B-10 Density from BADGER0.0190000.020000The reasons for this are that RACKLIFE calculates loss from an initial panel state(volumetric density and thickness).

The initial panel data for each panel was not provided byJoseph Oat (the manufacturer of the racks). A calculation of % loss isn't particularly usefulfor purposes of comparison to a criticality analysis unless one knows the starting point or hasa data point. A BADGER test provides that data point from which RACKLIFE can thenpredict when an areal density will be below the value assumed in the criticality analysis.

RACKLIFE uses a common escape coefficient (panel cavity volumes per day) for the wholepool and assumes uniform degradation across the whole panel. There can also be differences between individual panels either from construction anomalies or damage such that the wateringress/egress rate can vary from panel to panel. RACKLIFE and BADGER must be usedtogether to portray an accurate picture of the Boraflex panels.3. Yes, a similar percentage of the untested panels in the spent fuel pool would be expected tohave comparable degradation and thus may not meet the acceptance limit of 0.015656 gB-10/cm2.As panels with low B-10 are found with the BADGER test, fuel bundles will beremoved from the adjacent cells. When RACKLIFE predicts that a panel, previously tested2by BADGER, will degrade to below 0.015656 g B-10/cm , fuel bundles will likewise beremoved from the adjacent cells.The impact on the assumptions in the criticality Analysis of Record (AOR) is that morepanels (a similar percentage of-5%) would be below that minimum assumed AD of Enclosure I toNRC- 15-0031Page 280.015656 g B-1 0/cm 2. The AOR assumed a nominal AD of 0.01648 g B-10/cm2.Thedifference between this nominal AD and the minimum AD of 0.015656 g B-J O/cm2 is treatedas an uncertainty (rather than a bias) in the AOR. It is acceptable to treat this as anuncertainty in the AOR because the assumption is that even though there are panels that arebelow the nominal AD of 0.01648 g B-10/cm2, there are also panels whose AD is above thenominal AD. From the BADGER report, 16.7% of the panels tested had an AD below thenominal value but 83.3% were above the nominal value. Uncertainties are statistically combined (via Root Sum Square) in the AOR. The AOR also has an assumption for bundlereactivity in the cold core geometry of up to 1.31. This is because that is the bundlereactivity limit stated in Tech. Spec. 4.3.l.a.

Fermi 2 had a sensitivity study performed bythe fuel vendor that investigated the effects of increased Boraflex degradation.

For an arealdensity as low as 0.0 12 g B-10/cm2, a bundle reactivity of up to 1.2820 could be tolerated with a resulting rack k-effective of 0.945. The highest bundle reactivity that Fermi 2 has everhad was 1.2668. For all the Fermi 2 fuel, an areal density of as low as 0.012 g B-10/cm2could be tolerated with margin maintained to the rack k-effective limit of 0.95. Anadministrative limit on bundle k-infinity of 1.2820 was placed in the Fermi 2 procedure "Spent Fuel Storage Rack Management Guidelines."

It is reasonable to believe that the results of the 2013 BADGER test are representative of theentire population of Boraflex panels because of the sample size chosen. The statistically significant sample size of 60 panels was chosen based on the 95/95 criterion, i.e., for asample size of at least 59 panels, 95% of the population would be above the minimum valuetested with a 95% confidence level. The 95/95 criterion is an accepted industry practice anda sample size of 60 has become commonplace in the industry.

None of the panels testedduring the 2013 BADGER test were found to have an AD of less than 0.012 g B-10/cm2.Itis therefore reasonable to conclude that none of the Boraflex panels in the rack havedegraded to this point. In addition, the likelihood of finding an areal density of less than0.012 g B-10/cm2 is considered very low due to Fermi 2's Boraflex rack management strategy.

The Boraflex racks were installed in the early 1980s. For the first 2 refuel outages(1989 and 1991), Fermi 2 performed full core offloads to the same Boraflex cells in the SFP.For the 3rd and 4th refuel outages, Fermi 2 offloaded the core to a different area of the SFP tominimize Boraflex degradation.

Since RF04 (with 1 exception

-RF11) Fermi 2 hasperformed core shuffles which significantly reduce the amount of fuel bundles placed into theBoraflex racks. Fermi 2 had still maintained 4 non-poisoned GE rack modules containing 80cells. These cells relied upon geometric spacing to maintain sub-criticality.

Beginning inRF05, Fermi 2 would place approximately 76 of the hottest discharged bundles into thesenon-poisoned racks to minimize dose to the Boraflex racks. After allowing these 76 bundlesto cool for a cycle, they would then be moved to the Boraflex racks. Another strategy thatwas adopted in RF07 was to use the 108-cell (9x12) Boraflex rack module for the nexthighest dose bundles.

This strategy was adopted because this rack module was to bedischarged (and was discharged) during the 2007 re-rack campaign.

This resulted in keepingan additional 108 high-dose fuel bundles from the Boraflex racks that were going to remainin the pool during the period of extended operation (PEO).

Enclosure I toNRC- 15-0031Page 29In 2001, Fermi 2 added 3 Boral rack modules to the SFP during the Campaign 1 re-rack.This added 559 fuel storage cells. In 2004, an additional Boral rack module was placed intothe SFP (to accommodate a full core offload).

This added an additional 204 fuel storagecells. In 2007, the 108-cell Boraflex module and the 4 GE non-poisoned racks were removedfrom the pool during the Campaign 2 re-rack.

They were replaced by 5 Boral modules whichcomprised 630 fuel storage cells. As these Boral rack modules were introduced into the SFP,fuel from the reactor during refuel outages was preferentially placed into these Boral racks.They would only be moved over to the Boraflex racks after 1 cycle or more of cooling.

Thehigh-energy gamma dose from freshly discharged fuel decreases exponentially with time.This has had a major effect on minimizing the degradation to the Boraflex panels.As part of the Boraflex Monitoring and Corrective Action Programs, a condition assessment resolution document (CARD) was written on the results of the 2013 BADGER testing.Administrative actions were put into place to not use those cells whose panels were measuredto be less than the 0.015656 g B-10/cm2 limit for fuel storage.

Long term action is beingevaluated for Fermi 2, which will also consider operating experience from other plants.Also, a simple projection shows that areal density for none of the measured cells woulddecrease below 0.012 with tile current fuel in the cells for at least twenty years after the 2013test. RACKLIFE would need to project a 20% loss of boron carbide (B4C) to challenge the0.012 areal density needed to ensure the sub-criticality margin is maintained with the currentmaximum bundle reactivity of 1.2820. RACKLIFE projected a maximum loss of less than4% B4C at the time of the BADGER test (October 2013). While the fuel will likely bemoved to support core refueling and Independent Spent Fuel Storage Installation (ISFSI)campaigns, the projection indicates that BADGER testing every five years is reasonable.

Testing every five years is consistent with NUREG-1801 Section XL.M22 and industryoperating experience.

The next BADGER test (planned for 2018) will include 60 panels that have not been testedand some panels that were tested in 2013 so that trending and correlation between BADGERand RACKLIFE can be improved.

LRA Revisions:

None.

Enclosure 2 toNRC-15-0031 Fermi 2 NRC Docket No. 50-341Operating License No. NPF-43DTE Revised Response to NRC Request for Additional Information for the Review of the Fermi 2 License Renewal Application

-Set 15 RAI 2.4.4-2 and Set 16 RAI 4.1-1 Enclosure 2 toNRC- 15-0031Page 1Set 15 RAI 2.4.4-2Background.:

LRA Section 2.3.3. 7, "Fire Protection

-Water, " indicates that fire dampers mounted in walls,(for compliance with 10 CFR 50.48) are addressed in LRA Section 2.4.4, "Bulk Commodities,"

however, LRA Section 2.4.4 does not mention damper housings as a component type that issubject to an AMR. Similarly, LRA Section 2.4.2, "Water-Control Structures,

" "Residual HeatRemoval Complex" subsection also refers to fire dampers in walls; however, LRA Table 2.4-2does not include any damper housings as a component type subject to an AMR.Table NYB of the GALL Report defines "ducting and components" as including fire dampers.However, the SRP-LR and the GALL Report do not differentiate between air control or airflowdampers and fire dampers that are needed for compliance with 10 CFR 50.48.Issue:It is not clear to the staff if all fire damper assemblies in fire barriers (walls, ceiling, and floors)have been appropriately identified as a component type as being within the scope of licenserenewal and subject to an AMR.Request:Verify whether the fire damper assemblies mounted in fire barriers (i.e., not in HVAC ductwork) are within the scope of license renewal (e.g., in the residual heat removal complex) inaccordance with 10 CFR 54.4(a) and whether they are subject to an AMR in accordance with1O CFR 54.21(a)(1).

If they are not within the scope of license renewal and are not subject to anAMR, please provide justification for the exclusion.

Response

DTE previously responded to RAI 2.4.4-2 by letter dated January 15, 2015 (NRC-15-0009).

Theresponse to RAI 2.4.4-2 is revised to include additional information requested by the NRC on aclarification call held on March 6, 2015. The revised response below supersedes the responsepreviously provided on January 15, 2015.Fire damper assemblies mounted in fire barriers (walls, ceilings, and floors) outside of heating,ventilation and air conditioning (HVAC) ductwork are within the scope of license renewal inaccordance with 10 CFR 54.4(a) and are subject to aging management review (AMR) inaccordance with 10 CFR 54.21 (a)(1). The fire dampers perform an active function and are notsubject to aging management review. The fire damper housings are passive long-lived components subject to aging management review. The fire damper housings are included withthe component type "Fire protection components

-miscellaneous steel including framing steel" Enclosure 2 toNRC- 15-0031Page 2with a fire barrier (FB) intended function as shown in License Renewal Application (LRA)Tables 2.4-4 and 3.5.2-4.LRA Revisions:

None.

Enclosure 2 toNRC- 15-0031Page 3Set 16 RAI 4.1-1Background LRA Table 4.1-2 states that the current licensing basis (CLB) does not include any flow-induced vibration analyses for the Fermi 2 reactor vessel internal (R VI) components that would need tobe identified as TLAAs. The LRA states that the flow-induced vibration analyses for the RVIcomponents are not based on time-dependent assumptions defined by the life of the plant and,therefore, they do not conform to the definition of a TLAA in 10 CFR 54.3.IssueUFSAR Section 1.5.2.3 states that flow-induced vibrations of the RVI components were qualified by prototypical testing peiformed in accordance with General Electric (GE) Report No. NEDO-2405 7-P, "Assessment of Reactor Internals Vibration in BWR/4 and BWR/5 Plants, "datedNovember 1977, and this report is the design basis for demonstrating conformance with NRCRegulatory Guide (RG) 1.20, "Comprehensive Vibration Assessment Program for ReactorInternals During Preoperational and Initial Startup Testing.

" However; the UFSAR does notindicate whether the methodology in GE Report No. NEDO-2405 7-P includes a time-dependent analysis for qualifying the structural integrity of the RVI components against the consequences offlow-induced vibrations.

RequestClarify whether the methodology in GE Report No. NEDO-24057-P includes a time-dependent analysis and whether the analysis is relied upon to qualif the structural integrity of the R VIcomponents against the consequences offlow-induced vibrations.

If the analysis istime-dependent, providejustification as to why it would not need to be identified as a TLAAwhen compared to the six criteria in 10 CFR 54.3(a).Response:

DTE previously responded to RAI 4.1-1 by letter dated February 5, 2015 (NRC-15-0010).

Theresponse to RAI 4.1-1 is revised to include additional information requested by the NRC on aclarification call held on March 5, 2015. The revised response below supersedes the responsepreviously provided on February 5, 2015.The methodology in GE Report No. NEDO-24057-P does not include a time-dependent analysisas long as the flow-induced vibration stress is less than the GE criterion of 10,000 psi, 0-p. ThisGE criterion is more conservative than the ASME allowable peak stress intensity threshold of13,600 psi. Based on startup vibration measurements at the prototype plant, the maximum peakstress amplitude due to flow induced vibrations is less than 10,000 psi, 0-p. As discussed inUFSAR Section 3.9.1.3.2, the RVI for Fermi 2 are substantially the same internals designconfiguration that was tested in the prototype plant. Therefore, these results are applicable to Enclosure 2 toNRC- 15-0031Page 4Fermi 2. Since the value is less than 10,000 psi, O-p, no fatigue usage is accumulated by thecomponent due to flow-induced vibration (ASME Section III, Division 1, Appendix 1, Figure I-9.2.2, Design Fatigue Curve for Austenitic Steels).

Therefore, operating time has no effect onthe RVI component evaluation.

LRA Revisions:

None.