NRC-15-0067, Response to NRC Request for Additional Information for the Review of the License Renewal Application - Set 35

Response to NRC Request for Additional Information for the Review of the License Renewal Application - Set 35

ML15170A329
Person / Time
Site:	Fermi
Issue date:	06/18/2015
From:	Colonnello W DTE Energy
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
NRC-15-0067
Download: ML15170A329 (23)

Text

Vito A. Kaminskas Site Vice President DTE Energy Company 6400 N. Dixie Highway, Newport, MI 48166 Tel: 734.586.6515 Fax: 734.586.4172 Email: kaminskasv@dteenergy.com SDTE Entergy 10 CFR 54 June 18, 2015 NRC-15-0067 U. S. Nuclear Regulatory Commission Attention: Document Control Desk Washington D C 20555-0001

References:

1) Fermi 2 NRC Docket No. 50-341 NRC License No. NPF-43

2) DTE Electric Company Letter to NRC, "Fermi 2 License Renewal Application," NRC-14-0028, dated April 24, 2014 (ML14121A554)

3) NRC Letter, "Requests for Additional Information for the Review of the Fermi 2 License Renewal Application - Set 35 (TAC No.

MF4222)," dated May 21, 2015 (ML15134A072)

4) DTE Electric Company Letter to NRC, "Response to NRC Request for Additional Information for the Review of the Fermi 2 License Renewal Application - Set 25," NRC-15-0032, dated April 17, 2015 (ML15107A408)

Subject:

Response to NRC Request for Additional Information for the Review of the Fermi 2 License Renewal Application - Set 35 In Reference 2, DTE Electric Company (DTE) submitted the License Renewal Application (LRA) for Fermi 2. In Reference 3, NRC staff requested additional information regarding the Fermi 2 LRA. Enclosure 1 to this letter provides the DTE response to the request for additional information (RAI). Enclosure 2 to this letter provides a revised response to Set 25 RAI B.1.16-2a as discussed with the NRC during clarification calls on May 14 and 28, 2015. The response to RAI B.1.16-2a was previously provided in Reference 4.

No new commitments are being made in this submittal. However, revisions have been made to commitments previously identified in the LRA. The revised commitments are in LRA Table A.4 Item 11, External Surfaces Monitoring, as indicated in the response to RAI B.1.16-2a in Enclosure 2.

USNRC NRC-15-0067 Page 2 Should you have any questions or require additional information, please contact Lynne Goodman at 734-586-1205.

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

e tedon June 18, 20 Wayne A. Colonnello Director Nuclear Work Management For Vito A. Kaminskas

Enclosures:

1) DTE Response to NRC Request for Additional Information for the Review of the Fermi 2 License Renewal Application - Set 35

2) DTE Revised Response to NRC Request for Additional Information for the Review of the Fermi 2 License Renewal Application - Set 25 Question B.1.16-2a cc: NRC Project Manager NRC License Renewal Project Manager NRC Resident Office Reactor Projects Chief, Branch 5, Region III Regional Administrator, Region III Michigan Public Service Commission, Regulated Energy Division (kindschl @michigan.gov)

Enclosure 1 to NRC-15-0067 Fermi 2 NRC Docket No. 50-341 Operating License No. NPF-43 DTE Response to NRC Request for Additional Information for the Review of the Fermi 2 License Renewal Application - Set 35

Enclosure 1 to NRC-15-0067 Page 1 Set 35 RAI 4.3.3-1a

Background

By letter dated January 14, 2015, the staff issued Requestfor Additional Information (RAI) 4.3.3-1 requesting that the applicant:

(1) Provide the methodology being used to identify plant-specific component locations in the reactorcoolantpressure boundary that are more limiting than the components identified in NUREG/CR-6260.

(2) Provide the technical basis used to determine that the methodology used to identify the plant-specific component locations are bounding.

In its response dated February12, 2015, the applicantstated that:

(1) Electric PowerResearch Institute (EPRI) Technical Report 1024995, "Environmentally Assisted FatigueScreening, Process and Technical Basis for Identifying EAF Limiting Locations," is the methodology that will be used to identify plant-specific component locations that are more limiting than the locations identified in NUREG/CR-6260.

(2) EPRI Technical Report 1024995, Section 3, provides the technical basisfor the methodology to identify the limiting plant-specific component locations.

Section 3 of EPRI Technical Report 1024995 states: "The reader is reminded that this report is NOT provided as a Quality Assured document. Application of the processes described will require appropriatereview and quality dedicationon a site-specific basis."

Section 4 of EPRI Technical Report 1024995 contains a subsection entitled "Guidelinesfor Reducing the Number of Sentinel Locations." This subsectionprovides possible criteria that could be used to make judgements regardingthe reduction of sentinel locations. Section 6 also states that analysis beyond the scope of the screeningprocess presentedmay be applied to further reduce the number of sentinel locations.

Issue EPRI Technical Report 1024995 has not been submitted to the NRC for approval and has not been endorsedby the NRC. Additionally, EPRI Technical Report 1024995 is not a Quality Assured document and its applicationrequiresplant-specific review. The criteriaused to reduce the number of sentinel locations are not clearly defined. The applicanthas not demonstratedthat its applicationof the screeningmethodology will be done in a manner that conservatively evaluates environmentally assistedfatigue (EAF) effects, with the same degree of analytical rigorfor all locations, to identify the bounding locations.

to NRC-15-0067 Page 2 The staff lacks sufficient information to evaluate the effects of the reactorcoolant environment on componentfatigue life during the period of extended operation. It is unclear to the staff if the plant-specific implementation of the genericprocedures in EPRI Technical Report 1024995 will identify the most limitingplant-specific locations.

Request (1) Describe andjustify the site-specific review that was conducted to determine that the application of the screeningprocesses being utilized is appropriatefor identifying the EAF limiting locations.

(2) Select a number of representativesystems and provide the evaluation of the EAF analysis, ranking of sentinel locations, and selection of limiting sentinel locations. The systems should be selected so that they demonstrate the adequacy of the methodology to identify the limiting plant-specific component locations. Considerationshould be given to the thermal zones, materials, transients,and complexity of the systems selected. The systems selected should demonstrate that the methodology conservatively evaluates EAF effects, with the same degree of analyticalrigorfor all locations, to identify the bounding locations.

(3) Describe and justify any engineeringjudgement, plant-specific assumptions, and plant-specific criteriaused in the EAF analysis or screening process. This should include the systematic process used to eliminate sentinel locations as limiting and examples showing how the process was implemented.

Response

1) Fermi 2 has an ASME Section III design basis for Class 1 vessels and piping. Therefore, these components have calculated cumulative usage factors (CUFs). Fermi 2 utilized the EPRI Technical Report 1024995 guidelines for identifying Sentinel locations for a plant with an ASME Section III Subsection NB-3000 vessel and piping design basis. As noted in Section 2 of the EPRI report, "Evaluating components with a CUFcalculation is straightforwardand may require a relatively simple evaluationprocess to estimate and apply environmentalfatigue correctionfactors (Fenl) to the existing CUF values." The main reason for this relative simplicity is that usage has been calculated and can be recalculated in a straightforward manner using fatigue curves from the applicable NUREG for estimating EAF.

The design stress analysis results for Fermi 2 were previously reanalyzed for power uprate conditions, with updated CUFs for 60 years provided in LRA Table 4.3-2 (Reactor Pressure Vessel), LRA Table 4.3-4 (Reactor Recirculation Pumps), LRA Table 4.3-6 (Class 1 Piping),

and LRA Table 4.3-7 (Class 1 Valves). Each component location was examined and the location with the largest CUF was identified in each subsystem in the fatigue analysis. The calculations documenting the evaluation of the candidate locations evaluated these locations to NRC-15-0067 Page 3 for EAF. The evaluations were performed under the auspices of a 10 CFR 50 Appendix B quality assurance program. Therefore, the screening process used for Fermi 2 is robust and comprehensive.

2) The Feedwater (FW) system and Standby Liquid Control (SLC) system are the systems selected as representative systems.

FW System The FW system was divided into subsystems for the purpose of this screening process; nozzle, piping inside containment, containment penetration and piping outside containment.

The piping and containment penetration material is carbon steel, the nozzle is low alloy steel, and the safe end is stainless steel.

The design stress analysis results were examined and the location with the largest CUF was identified in each subsystem. These locations had been reanalyzed for power uprate conditions and, as indicated in LRA Section 4.3, 60-year projected cycles. The results obtained from the process for evaluating Sentinel locations for the FW system are provided in Table 1 of this response.

As can be observed from the notes on Table 1, the same degree of analytical rigor was not always applied. Therefore, the approach used at Fermi 2 took this into account when selecting Sentinel locations and is why some Sentinel locations with currently lower calculated CUF values were selected (e.g., FW piping FW-04 Node 16 instead of the penetration body - see Table 1 Notes 1, 2 & 9). Alternating stress and fatigue usage is highest where large, rapid temperature changes occur (e.g., FW nozzle and FW-04 Node 16 where FW, RCIC and RWCU systems converge), validating the selection of these locations as Sentinel locations.

SLC System The SLC piping both outside and inside containment up to the nozzle was evaluated for EAF, as well as its associated nozzle (core AP nozzle). The core AP nozzle is not one of the NUREG/CR-6260 locations, but was determined to be a Sentinel location based on its CUFen value. The results are provided in Table 2 of this response.

Node 55 is the highest fatigue location in the piping system with a 60-year CUF value of 0.097. Node 95 is the highest fatigue location in the piping outside containment with a 60-year CUF value of 0.056. The CUFen value for Node 55 is 0.503. The nozzle through which the SLC fluid enters the RPV is the core AP nozzle, whose 60-year CUF value is 0.637 with a calculated CUFen value of 1.478. The core AP nozzle thus bounds the piping and will serve as a Sentinel location. Although a NB-3200 analysis was performed for the core AP nozzle, the calculated 60 year usage was conservatively calculated by combining the transients and evaluated using the alternating stress for the most limiting transient case. It is anticipated that further analytical work will be performed in the future to demonstrate that the computed CUFen value of the core AP nozzle is acceptable. This may result in Node 55 being to NRC-15-0067 Page 4 identified as an additional Sentinel location if the CUFen value is within 50% of the core AP nozzle CUFen value.

to NRC-15-0067 Page 5 Table 1: CUF Values from LRA and CUFen Values Using 60-year Cycle Projections - FW System ASME Fatigue Curve NUREG/CR-6909 Fatigue Curve and Fen Location Material Node CUF (60- CUF (60- CUFen (60- Sentinel Identifier year cycles) year cycles) year cycles) Location Blend Radius/Nozzle-Vessel LAS N/A 0.058 0.036 0.115 Y( 3)

Intersection FW Nozzle Safe-End SS N/A 0.585 0.664 6.366(10) Y(3)

Safe-End/Nozzle End CS N/A 0.267 0.087 0.165 Y(3)

FW-01 Piping inside containment CS 40 0.071 0.026 0.049 N(4-5 FW-02 Piping inside containment CS 40 0.101 0.037 0.070 N(4'5 Piping outside containment CS 6 6 16 0.192(15) N/CC) N/C( (3 )

__ -04 Piping outside containment CS 16 0.003(2) 0.0003 0.0012 FW-05 Piping outside containment CS 305 0.010(5) Bounded by FW-04 7 N(

X-9A weld(8 ) CS N/A 0.047 0.016 0.029 N(

8 Penetrations X-9B weld( CS N/A 0.096 0.033 0.062 N(

9 X-9A/B body( ) CS N/A 0.471 0.208 0.391 N(9 )

Notes:

(1) NB-3600 fatigue analysis revised to account for new RWCU out of service transient. Piping location with highest usage prior to reanalysis.

(2) Detailed 3-D N1B-3200 reanalysis of RWCU-RCIC tee significantly reduced usage at what was the bounding piping location.

(3) NUREG/CR-6260 location. FW nozzle includes all material types. Detailed 3-D NB-3200 analysis performed of the nozzle and tee locations.

(4) Bounded by other piping locations.

(5) Piping location. NB-3600 analysis performed.

(6) N/C - Not calculated. Calculated for the refined analysis case.

(7) FW-04 location had higher usage prior to detailed 3-D reanalysis.

(8) Flued head to piping weld. 2-D NB-3200 analysis performed. Individual transients evaluated for fatigue contribution.

(9) Flued head body location. Transient cycles were lumped together and evaluated using the alternating stress for the most limiting transient, so the CUF is significantly more conservative than the other FW locations.

(10) CUFen > 1.0. Further action required.

to NRC-15-0067 Page 6 Table 2: CUF Values from LRA and CUFen Values Using 60-year Cycle Projections - SLC System ASME Fatigue Curve NUREG/CR-6909 Fatigue Curve and Fen System Location Material Node CUF (60- CUF (60- CUFen (60- Sentinel Component /

year cycles) year cycles) year cycles) Location Location Core AP Nozzle Outside surface"l) Inconel N/A 0.637 0.580 1.4784 Y(l)

Piping Piping inside containment SS 55 0.097(2) 0.108 0.503 No 3 3 Piping Piping outside containment SS 95 0.056 N/C ) N/C ) N(3 )

Weld SS N/A 0.002 N/C 3 ) N/C 3 )

Penetration X-42 NC /NN Body SS N/A 0.001 Notes:

(1) Bounding CUF location in SLC system. Analyzed using more rigorous design by analysis (NB-3200) methods.

(2) Analysis used design by rule (NB-3600) approach. Use of 1977 Code with 1979 Addenda reduced usage from the original design analysis.

(3) N/C - Not calculated. Bounded by Node 55.

(4) CUFe > 1.0. Further action required.

to NRC-15-0067 Page 7

3) The site-specific application of the screening process for identifying EAF limiting locations comprised the following activities:

Fermi 2-specific fatigue analyses were performed for Class 1 reactor coolant pressure boundary locations with reported CUF values using the design fatigue curves from NUREG/CR-6909, Revision 0.

o Locations not wetted (not in contact with reactor water) were screened out (e.g. HPCI steam line).

o Components with the highest design CUF were evaluated for the effects of EAF.

o For each system evaluated, EAF was calculated for each material type present (e.g. carbon steel, low alloy steel, stainless steel, Ni-Cr-Fe alloy / Inconel).

• To calculate Fen multipliers, the following assumptions were used:

o Fermi 2-specific historical dissolved oxygen values for each reactor water chemistry zone were used.

o Strain rate values that maximize EAF in the NUREG/CR-6909 equations for EAF were used.

o Sulfur values that maximize EAF in the NUREG/CR-6909 equations for EAF were used (applies only to carbon and low alloy steels).

Fen multipliers were developed for various temperatures for carbon steel, low alloy steel, stainless steel and Ni-Cr-Fe alloy for each of six listed reactor water chemistry zones. Fen multipliers also considered dissolved oxygen (DO) levels associated with the plant water chemistry history and accounted for the Normal Water Chemistry (NWC), Hydrogen Water Chemistry (HWC) and On-line Noble Metal Chemistry (OLNC) availability. CUFen calculations were initially made using these zone-specific Fen values at the maximum design transient temperature of 575°F.

Thus, CUFen values were initially calculated assuming the least favorable conditions for metal sulfur content, component strain rate and temperature along with the zone-specific DO values.

The plant fluid systems were subdivided into subsystems in a manner consistent with the fatigue analyses comprising the current design basis and the screening process compared all components in the same fluid subsystem. Thus, this screening approach inherently addressed all thermal zones.

The following systems and locations identified in NUREG/CR-6260 were addressed. All these locations are Sentinel locations.

• Feedwater o Nozzle (all materials) o FW piping where RCIC/RWCU are connected (more severe than where HPCI is connected)

• Core spray o Nozzle (all materials) to NRC-15-0067 Page 8 o Piping

• Reactor Recirculation o Inlet nozzle (all materials) o Outlet nozzle (all materials) e RHR o Supply piping o Return piping

• Reactor Vessel shell and lower head o RPV shell o CRD nozzle For completeness, in addition to the NUREG/CR-6260 locations, the RWCU piping, Reactor Recirculation piping and SLC nozzle and piping were evaluated.

Additional Sentinel locations were selected by the following process. For each fluid system:

1. Select the location with the largest CUFen value for each material present.

2. Eliminate locations with CUFen values less than a value of 0.8 (unless the location is part of a component with other materials present some of whose CUFen values exceed 0.8).

3. Retain the remaining locations with the second largest CUFen of a given material if it is within 50% of the value of the largest location in that fluid system. Eliminate any remaining locations.

Engineering judgment was used to address dynamic and rapid cycling loads. NUREG/CR-6909 states in Section 4.2 that existing fatigue data indicates that a slow strain rate applied during a tensile-loading cycle is primarily responsible for environmentally assisted reduction in fatigue life and also states that when all threshold conditions are satisfied, the fatigue life of carbon and low-alloy steels decreases logarithmically with decreasing strain rate below 1%/s. Accordingly, transient pairs which had solely dynamic or rapid cycling loading values had no environmental fatigue multipliers applied (Fen = 1.0).

Subsequent to this establishment of Sentinel locations, additional refined analysis was performed for those Sentinel locations with CUFen values exceeding a value of 1.0 with the intention of achieving CUFen values of 1.0 or less. Where this occurred, these locations were re-evaluated with reduced Fen multipliers using average transient temperatures (based on NUREG/CR-6909 guidance) or where load pairs subject to dynamic loading for the load pair in question (e.g., OBE) were directly available in the listed inputs.

Sentinel locations with a calculated projected CUFen greater than 1.0 as a result of the screening activity were identified as requiring additional action prior to actually exceeding this value.

to NRC-15-0067 Page 9 LRA Revisions:

None.

Enclosure 2 to NRC-15-0067 Fermi 2 NRC Docket No. 50-341 Operating License No. NPF-43 DTE Revised Response to NRC Request for Additional Information for the Review of the Fermi 2 License Renewal Application -

Set 25 Question B.1.16-2a

Enclosure 2 to NRC-15-0067 Page 1 Set 25 RAI B.1.16-2a

Background

The response to requestfor additional information (RAI) B.1.16-2, dated January28, 2015, states that the External Surfaces MonitoringProgram will be revised to inspect insulated components to ensure that moisture intrusionhas not degraded the insulation when the insulation is requiredto reduce heat transfer. Commitment No. 11h and Enhancement No. 8 were added to revise the programprocedures to include instructionsfor the inspection of both jacketed and non-jacketed insulationfor insulation degradationdue to moisture intrusion.

GenericAging Lessons Learned (GALL) Report Aging ManagementProgram(AMP) XI.M36, as revised by License Renewal Interim Staff Guidance (LR-ISG)-2012-02, "Aging Management of Internal Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and Corrosion Under Insulation," provides guidance on the inspection ofjacketed insulation to manage reduced heat transfer. The "detection of aging effects" program element states that if configurationfeatures, such as minimum overlap and seam locations, associatedwith jacketed insulation are not applicablethat an alternativeinspection methodology should be proposed to address reduced thermal insulation resistance.

Issue The staff lacks the informationnecessary to evaluate the aging management of reduced thermal insulation resistanceof non-jacketed insulation. The External Surfaces Monitoring Program does not include an inspection methodology or frequency to detect reduced thermal insulation resistancedue to moisture intrusionfor non-jacketed insulation.

Request Provide the inspection methodology andfrequency used to manage reduced thermal insulation resistancefor non-jacketed insulation. State the basisfor the inspection methodology and frequency.

Response

DTE previously responded to RAI B.1.16-2a by letter dated April 17, 2015 (NRC-15-0032). The response to RAI B.1.16-2a is revised to include additional information requested by the NRC on clarification calls held on May 14 and 28, 2015. The revised response below supersedes the response previously provided on April 17, 2015.

Visual inspection of jacketed and non-jacketed insulation that performs an intended function of "insulation" will be conducted in accordance with the External Surfaces Monitoring Program.

Visual inspection of this insulation will occur at a frequency consistent with NUREG-1801 Section XI.M36, as modified by LR-ISG-2012-02. Potential water intrusion will be considered.

to NRC-15-0067 Page 2 Signs of water intrusion would include discoloration, staining, or surface irregularities. It is expected that insulation that shows no sign of discoloration, stains, or surface irregularities would perform its intended insulation function. Enhancements in the External Surfaces Monitoring Program (LRA Sections A.1.16 and B.1.16) will be revised to include a description of these activities.

In addition, non-jacketed thermal insulation with the intended function of "insulation" will be monitored through the Periodic Surveillance and Preventive Maintenance (PSPM) Program. In each five-year period beginning five years prior to the period of extended operation (PEO) where plant conditions permit (i.e., the insulated pipe is carrying a heat load and is not located in a high radiation area), thermography of at least 20 percent of the available population will be performed to assess its insulating ability. A revision to the PSPM Program (LRA Sections A.1.35 and B.1.35) will be made to include a description of these activities.

LRA Revisions:

LRA Table 3.5.2-4 and LRA Sections A.1.16, A.1.35, A.4, B.1.16, and B.1.35 are revised as shown on the 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-14-005 1), January 15, 2015 letter (NRC-15-0002), and January 28, 2015 letter (NRC-15-0007) are not shown in underline or strike-through such that only the new changes due to RAI B.1.16-2a are shown as revisions.

to NRC-15-0067 Page 3 Table 3.5.2-4 Bulk Commodities Summary of Aging Management Evaluation Table 3.5.2-4: Bulk Commodities Structure and/or Component Aging Effect Aging NUREG-or Intended Requiring Management 1801 Table Commodity Function Material Environment Management Programs Item 1 Item Notes Insulation IN, SNS Fiberglass, Air - indoor Loss of External J (includes calcium uncontrolled material, Surfaces jacketing, silicate, Change in Monitoring wire mesh, Fiberfrax, material Periodic tie wires, fiberfrax properties, Surveic straps, clips) ceramic Degradation and fiber due to durablanket, moisture Mainte Insulfrax intrusion Maintenance to NRC-15-0067 Page 4 A.1.16 External Surfaces Monitoring Program Acceptance criteria are defined to ensure that the need for corrective action is identified before a loss of intended function. For stainless steel, a clean shiny surface is expected. For flexible polymers, a uniform surface texture (no cracks) and no change in material properties (e.g.,

hardness, flexibility, physical dimensions, color unchanged from when the material was new) are expected. For rigid polymers, no surface changes affecting performance, such as erosion, cracking, crazing, checking, and chalking, are acceptable. For insulation, no discoloration, staining, or surface irregularities from moisture intrusion is expected.

The External Surfaces Monitoring Program will be enhanced as follows.

e Revise External Surfaces Monitoring Program procedures to include acceptance criteria for the parameters observed.

• Metals should not have any indications of relevant degradation.

pi Flexible polymers should have a uniform surface texture and color with no cracks and no dimension change, no abnormal surface conditions with respect to hardness, flexibility, physical dimensions, and color.

• Rigid polymers should have no erosion, cracking, crazing, or chalking.

& For insulation, no discoloration, staining, or surface irregularities from moisture intrusion.

• Revise External Surfaces Monitoring Program procedures to stipulate that administrative controls are in accordance with the Fermi 2 10 CFR 50 Appendix B Quality Assurance Program.

• Revise External Surfaces Monitoring Program procedures to include instructions for detection of cracking of gas-filled stainless steel and aluminum components exposed to outdoor air.

Revise External Surfaces Monitoring Program procedures to: a) Visually inspect jacketed and non-jacketed insulation required to reduce heat transfer at a freguency consistent with NUREG-1801 Section XI.M36, as modified by LR-ISG-2012-02, to ensure that insulation degradation due to moisture intrusion has not occurred. b) Ensure procedures include instructions to inspect for signs of water intrusion. Inspect accessible surfaces for the following signs of water intrusion: discoloration, staining, or surface irregularities.

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

to NRC-15-0067 Page 5 A.1.35 Periodic Surveillance and Preventive Maintenance Program The Fermi 2 aging management review credits the following inspection activities.

Visually inspect and manually flex the rubber gasket/seal for reactor building spent fuel storage pool gates to verify no loss of sealing.

• Determine wall thickness of selected service water system piping components to manage loss of material due to recurring internal corrosion by multiple corrosion mechanisms.

• Visually inspect a representative sample of emergency diesel generator (EDGE, system air coolant, lube oil, and jacket water heat exchanger tubes to manage loss of material due to wear.

• Determine wall thickness of selected EDG system piping components to manage loss of material due to recurring internal corrosion by multiple corrosion mechanisms.

o Use visual or other NDE techniques to inspect internal surfaces to manage fouling of the fire water system heat exchanger tubes exposed to raw water.

• Visually inspect a representative sample of the dry piping downstream of the manual isolation valve for the cable spreading room wet pipe system for flow blockage. The first inspection will be within five years of the period of extended operation.

• Visually inspect a representative sample of combustion turbine generator (CTG) system lube oil heat exchanger tubes to manage loss of material due to wear.

o Visually inspect a representative sample of CTG system atomizing air precooler heat exchanger tubes to manage fouling and loss of material due to wear.

• Visually inspect and clean CTG system atomizing air booster compressor suction filter to manage fouling.

• Visually inspect and clean CTG system compressor extraction air filter to manage fouling.

• Use visual or other NDE techniques to inspect containment atmospheric control system recombiner components' internal surfaces to manage loss of material.

Perform thermography on a sample of non-jacketed insulation having an intended function of "insulation" to assess its insulating ability. A sample will consist of at least 20 percent of the available population of non-jacketed insulation where the insulated piping has a heat load and is not located in a high radiation area. The first thermography will be during the five years prior to the period of extended operation.

to NRC-15-0067 Page 6 A.4 LICENSE RENEWAL COMMITMENT LIST No. Program or Commitment Implementation Source Activity Schedule 11 External Surfaces Enhance External Surfaces Monitoring Program as follows: Prior to A.1.16 Monitoring September 20,

e. Revise External Surfaces Monitoring Program 2024.

procedures to include acceptance criteria for the parameters observed.

" Metals should not have any indications of relevant degradation.

" Flexible polymers should have a uniform surface texture and color with no cracks and no dimension change, no abnormal surface conditions with respect to hardness, flexibility, physical dimensions, and color.

• Rigid polymers should have no erosion, cracking, crazing, or chalking.

" For insulation, no discoloration, staining, or surface irregularities from moisture intrusion.

to NRC-15-0067 Page 7 Program or Implementation No. Activity Commitment Impee Source

h. Srac nitoring Program Schue etorna inSUlationR rogu rod to reducs heat trnsfc~rr to rao en inSulation dogradation duo- to moiisro, inetruso hean - rnt roeure. Tho insintruction f modn in itr oftin guidance for both jackotod and non jacketod insulation.

Revise External Surfaces Monitoring Program procedures to: a) Visually inspect iacketed and non-jacketed insulation required to reduce heat transfer at a frequency consistent with NUREG-1801 Section XI.M36, as modified by LR-ISG-2012-02, to ensure that insulation degradation due to moisture intrusion has not occurred. b) Ensure procedures include instructions to inspect for signs of water intrusion. Inspect accessible surfaces for the following signs of water intrusion:

discoloration. staining, or surface irregularities.

to NRC-15-0067 Page 8 B.1.16 EXTERNAL SURFACES MONITORING Program Description For polymeric materials, the visual inspection will include 100 percent of the accessible components. The sample size of polymeric components that receive physical manipulation is at least ten percent of the available surface area.

Examples of inspection parameters for (jacketed and non-jacketed) insulation include the following:

• Discoloration Staining

• Surface irregularities Acceptance criteria are defined to ensure that the need for corrective action is identified before a loss of intended function. For stainless steel, a clean shiny surface is expected. For flexible polymers, a uniform surface texture (no cracks) and no change in material properties (e.g.,

hardness, flexibility, physical dimensions, color changed from when the material was new) are expected. For rigid polymers, no surface changes affecting performance such as erosion, cracking, crazing, checking, and chalking, are acceptable. For insulation, no discoloration, staining, or surface irregularities from moisture intrusion is expected.

Enhancements Element Affected Enhancement

3. Parameters Monitored or RoisEt ua nng Progra Inspected preco t nlu ueten4enter4yef

4. Detection of Aging Effects insulation requi-ed t rdu eheat trsfr to intruslon-has-not-occuredhese4instructioFFns incud ispctongudacofo bthjaketed-ad onacktd insulation Revise External Surfaces Monitoring Program procedures to: a) Visually inspect jacketed and non-jacketed insulation required to reduce heat transfer at a freguency consistent with NUREG-1801 Section XI.M36, as modified by LR-ISG-2012-02, to ensure that insulation degradation due to moisture intrusion has not occurred. b) Ensure procedures include instructions to inspect for signs of water intrusion. Inspect accessible surfaces for the following signs of water intrusion: discoloration, staining, or surface irregularities.

to NRC-15-0067 Page 9 Element Affected Enhancement

6. Acceptance Criteria Revise External Surfaces Monitoring Program procedures to include acceptance criteria for the parameters observed.

• Metals should not have any indications of relevant degradation.

• Flexible polymers should have a uniform surface texture and color with no cracks and no dimension change, no abnormal surface conditions with respect to hardness, flexibility, physical dimensions, and color.

• Rigid polymers should have no erosion, cracking, crazing, or chalking.

For insulation, no discoloration, staining, or surface irregularities from moisture intrusion.

Enclosure 2 to NRC-15-0067 Page 10 B.1.35 PERIODIC SURVEILLANCE AND PREVENTIVE MAINTENANCE The Fermi 2 aging management review credits the following inspection activities.

Reactor Visually inspect and manually flex the rubber gasket/seal for spent fuel storage building pool gates to verify no loss of sealing.

Service water Determine wall thickness of selected service water system piping components system to manage loss of material due to recurring internal corrosion by multiple corrosion mechanisms.

Emergency Visually inspect a representative sample of EDG system air coolant, lube oil, diesel and jacket water heat exchanger tubes to manage loss of material due to wear.

generator Determine wall thickness of selected EDG system piping components to (EDG) system manage loss of material due to recurring internal corrosion by multiple corrosion mechanisms.

Fire water Use visual or other NDE techniques to inspect internal surfaces to manage system fouling of the fire water system heat exchanger tubes exposed to raw water.

Visually inspect a representative sample of the dry piping downstream of the manual isolation valve for the cable spreading room wet pipe system for flow blockage. The first inspection will be within five years of the period of extended operation.

Combustion Visually inspect a representative sample of CTG system lube oil heat exchanger turbine tubes to manage loss of material due to wear.

generator Visually inspect a representative sample of CTG system atomizing air precooler (CTG) system heat exchanger tubes to manage fouling and loss of material due to wear.

Visually inspect and clean CTG system atomizing air booster compressor suction filter to manage fouling.

Visually inspect and clean CTG system compressor extraction air filter to manage fouling.

Containment Use visual or other NDE techniques to inspect containment atmospheric control atmospheric system recombiner components' internal surfaces to manage loss of material.

control system Non-iacketed Perform thermography on a sample of non-jacketed insulation having an insulation intended function of "insulation" to assess its insulating ability. A sample will consist of at least 20 percent of the available population of non-iacketed insulation where the insulated piping has a heat load and is not located in a high radiation area. The first thermography will be during the five years prior to the period of extended operation.