ML23172A147

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Breakout Questions - Aging Management Audit - Comanche Peak Units 1 and 2 - License Renewal Application
ML23172A147
Person / Time
Site: Comanche Peak  Luminant icon.png
Issue date: 08/09/2023
From: Mark Yoo
NRC/NRR/DNRL/NLRP
To: Peters K
Vistra Operations Company
References
EPID L-2022-RNW-0018
Download: ML23172A147 (183)
v • d • e


Text

BREAKOUT QUESTIONS Aging Management Audit Comanche Peak Nuclear Power Plant, Units 1 and 2 License Renewal Application December 12, 2022 - May 18, 2023

Comanche Peak Nuclear Power Plant, Units 1 and 2 License Renewal Application (LRA) Breakout Audit Questions Fire Protection Scoping and Screening:

Section 2.3.3.7 Fire Protection System Section 2.4.15 Fire Barrier Commodity Group LAR Table 2.3.3-6 Equipment and Floor Drainage System Component Intended Function LAR Table 2.3.3-7 Fire Protection System Components Subject to Aging Management Review LAR Table 2.4-15 Fire Barrier Commodity Group Subject to Aging Management Review Question LRA Section LRA Background / Issue Discussion Question / Request Number Page (As applicable/needed) 1 2.3.3.7 2.3-80 The descripton of the fire protection system does Clarify whether there are fire protection not describe seismic support for fire water storage system components that are seismically tanks, standpipes, and piping that is within the supported and are within the scope of scope of license renewal in accordance with 10 license renewal in accordance with 10 CFR 54.4(a) and subject to an aging management CFR 54.4(a) and whether they are review (AMR) in accordance with 10 CFR subject to an AMR in accordance with 54.21(a)(1). 10 CFR 54.21(a)(1). If the components are not within the scope of license renewal and are not subject to an AMR, provide justification for the exclusion.

2 2.3.3.7 2.3-82 Oil collection dikes and curbs are credited fire Clarify whether there are other oil protection features. The LRA, however, only collection dikes and curbs such as for specifies the Reactor Coolant System (RCS) Oil the diesel oil and day tanks, pumps, etc.

Spillage Protection System. and whether they are within the scope of license renewal in accordance with 10 CFR 54.4(a) and whether they are subject to an AMR in accordance with 10 CFR 54.21(a)(1). If they are not within the scope of license renewal and are not subject to an AMR, provide justification for the exclusion.

3 2.4.15 2.4-45 The fire barrier commodity group describes cable Explain the differences between the two raceway fire barriers as well as insulation and wrap. systems and clarify whether any other It is unclear to the NRC staff what the difference is electrical raceway fire barrier systems between the two. (ERFBS) credited for cable tray, conduits, bus ducts, electrical panels or junction boxes, etc., are within the scope of license renewal in accordance with 10 CFR 54.4(a) and whether they are subject to an AMR in accordance with 10 CFR 54.21(a)(1). If they are not within the scope of license renewal and are not subject to an AMR, provide justification for the exclusion.

Comanche Peak Nuclear Power Plant, Units 1 and 2 License Renewal Application (LRA) Breakout Audit Questions LRA Section /XI.E2 AMP/OpE/X.E1 EQ:

TRP: 50 Question LRA LRA Background / Issue Discussion Question / Request Number Section Page (As applicable/needed) 1 XI.E2 In the LRA, the applicant noted that XI.E2 is consistent Basis with all the Elements described in NUREG-1801 XI.E2, document Insulation Material for Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits. However, LUM00020-REPT-075 - Insulation Material for Electrical Cables and Connections not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits Program Basis Document, states the following; For any instances where the CPNPP Insulation Material for Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits AMP does not meet the guidance of the NUREG-1801 XI.E2 Insulation Material for Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits AMP, additional actions which are necessary to align the CPNPP Insulation Material for Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits AMP with the guidelines are identified, or an exception with justification is provided.

Given this above, did the applicant identify any instances where the CPNPP Insulation Material for Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in

Instrumentation Circuits AMP does not meet the guidance of the NUREG-1801 XI.E2 Insulation Material for Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits AMP? If so, what actions were taken to align the CPNPP Insulation Material for Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits AMP with the LR guidelines including any justified exceptions that may have been taken.

2 OpE OpE Can you explain how the condition of cables (in general) will be monitored and if there are any trigger points (e.g.,

cables exposed to environmental conditions that may accelerate aging) for increasing the periodicity of monitoring/testing during the extended period of operation.

3 OpE OpE Explain the water trend fluctuation OpE (WR#4160865,WR#4329142,WR#4540006,WR#4593784) for the Unit#2 Train B electrical manhole inspection-service water. Discuss any impact this has had on your manhole inspection process in support of your request to renew the license for the plant.

4 OpE OpE Explain how the operational experience in CR2015-004409 which identified water coming out of a conduit and that the conduit was rusted, was resolved and discuss any impact this has had on your proposed aging management programs for cables (specifically XI.E3).

5 X.E1 EQ In LUM00020-REPT-081, Comanche Peak Nuclear Power Plant Units 1 and 2 License Renewal Time-Limited Aging Analysis-Environmental Qualification of Electrical Equipment, Rev. 1, the licensee stated Any changes to material activation energy values as part of a reanalysis must be justified. Per RG 1.89, Rev. 1, these changes

would also have to be defined and documented. Confirm that this is the case for any changes to material activation energy for establishing environmental qualification of electrical equipment at Comanche Peak.

6 X.E1 EQ With regard to CR-2017-012269, have the EQ files been updated and considered up to date?

7 X.E1 EQ Has the licensee relied on Electric Power Research Institute (EPRI) Report NP-1558, A Review of Aging Theory and Technology, dated September 1980 to establish or maintain qualification of electrical equipment at Comanche Peak? If so, EPRI recently updated this report (July 2020) due to issues/concerns with lack of or expired technical references for certain activation energies. The NRC staffs understanding is that this revision resulted in up to 30% of activation energies being removed from the database.

For environmentally qualified (EQ) components that the licensee used/relied upon EPRI Report NP-1558 as the justification/basis for activation energies for extending the qualified life of EQ equipment, has the licensee reviewed this revised document to verify that their justification/basis for activation energies remains valid for EQ components for the requested period of operation?

8 Sections Pages ISG-5 Section 3.6.2.3, AMR Results Not Consistent With or Not 2.5 and 2.5-2 NUREG-1800, Table 2.1-5 Addressed in the GALL Report, 3.6.2.3 and (Fuse 3.6-10 Consistent with NUREG-1801, XI.E5, the Holders) (Fuse screening of CPNPP fuse holders (metallic Table Holders) clamps) applies to those that are not part of a 2.5-1 Page larger (active) assembly. Fuse holders 2.5-5 inside the enclosure of an active component, such as switchgear, power supplies, power inverters, battery chargers, and circuit boards are considered piece parts of

the larger assembly. Since piece parts and subcomponents in such an enclosure are routinely inspected and regularly maintained as part of the plants normal maintenance and surveillance activities, they are not subject to AMR.

An evaluation of fuse holders at CPNPP was performed to discover the population of fuse holders that were not located in active devices, such as control panels, switchgear, MCCs and termination cabinets.

Panels, racks, and termination cabinets were also considered to be another type of active component consistent with the guidance provided in ISG-5 and were eliminated from the process.

ISG-5 states, in part:

The staff concludes that fuse holders are passive, long-lived electrical components within the scope of license renewal and subject to an AMR.

However, fuse holders inside the enclosure of an active component, such as switchgear, power supplies, power inverters, battery chargers, and circuit boards, are considered to be piece parts of the larger assembly.

For license renewal purposes, fuse holders/blocks are classified as a specialized type of terminal block because of the similarity in design and construction. Terminal blocks are passive components subject to an AMR for license renewal. However, like fuses, terminal blocks located inside the enclosure of an active component are considered to be piece parts of the

larger assembly and, thus, are outside the scope of license renewal.

The staff notes that, based on the guidance in ISG-5, panels, racks, and termination cabinets would be considered active components if they included active electrical/electronic components. This is consistent with the guidance in NUREG-1800, Table 2.1-5, Typical Structures, Components, and Commodity Groups, and 10 CFR 54.21(a)(1)(i) Determinations for Integrated Plant Assessment which provides switchgear, load centers, motor control centers (MCCs), distribution panel, and internal component assemblies as active electrical and I&C component commodity group and not meeting the criteria of 10 CFR 54.21(a)(1)(i). In addition, the staff notes that the applicant did not list racks and termination cabinets as electrical and I&C component commodity group in the LRA, Table 2.5-1, Typical Structures, Components, and Commodity Groups, and 10 CFR 54.21(a)(1)(i) Determinations for Integrated Plant Assessment.

Question: Please clarify if the above-mentioned panels, racks, and termination cabinets include active electrical/electronic components. Also, explain why the racks and termination cabinets are not listed in the electrical and I&C component commodity groups of Table 2.5-1 of the LRA.

9 Pages FSAR, page 8.3-40 In the LRA section 3.6.2.3 and section 2.5.1.3, 2.5-2 Elimination of Electrical and I&C Commodity Groups Not and Applicable to CPNPP, the applicant stated that the fuse 3.6-10 holders (metallic clamps) at CPNPP are considered piece (Fuse parts of a larger (active) assembly, and therefore they do Holders) are not subject to an aging management review for LR.

The staff is unable to confirm the applicants above-mentioned statement (i.e., CPNPP fuse holders, are pieces part of larger active assembly) for some fuses based on the FSAR descriptions of the fuses. Specifically, on page 8.3-40 of the FSAR (page 3152 of the pdf), the applicant states:

The Class 1E Electronics Boxes (X-LY-4849A-1, X-LY-4849A-2, X-LY-4849B-1 and X-LY-4849B-2) are connected to the Non-Class 1E annunciator in the Spent Fuel Pool Panel CPX-EIPRLV-06. At the Electronics Box, the Class 1E Cables from the level switches and 120V AC power supply cable enter the box from the top where as the Non-Class 1E cables from the annunciator enter the box from the bottom. The cables from the Class 1E Electronics Boxes to the plant computer are Non-Class 1E. The conductors originate at a Class 1E I/O board and is routed through an isolation device to the terminal block within the Electronics Box. To ensure the isolation device is protected from hot shorts, each conductor is independently fused between the isolation device and the terminal block. Two 1/4 amp, 250 VAC Class 1E fuses on the + and - of the isolator output are used for protection. These fuses will open under an abnormal faulted circuit condition to prevent damage to the isolator. The circuit is considered to be Non-Class 1E after the Class 1E fuses. The conductors are routed away from any Class 1E device inside the Electronics Boxes, and are landed below the annunciator circuits on the terminal block. However, inside the Electronics Box the Class 1E and Non-Class 1E Cables both terminate on the same terminal block. The terminal

block is heavy duty, barrier type, rated 600 Volts and 75 Amps AC, with breakdown voltage 13,000 V RMS line to line. The line to line spacing between the terminals is 0.66 inches. Non-Class 1E Cables are rated at 600 V AC and are fire retardant.

The Non-Class 1E Cables that originate from the Spent Fuel Panel CPX-EIPRLV-06 annunciator are wired to the dry contacts of Class 1E relays installed in the Electronics Box.

Its not clear to the staff if the above-mentioned Class 1E fuses are located inside an active electrical equipment/enclosure/electronic box.

Question: Please clarify where the above-mentioned Class 1E fuses are in terms of the active component in which they are located.

10 Page FSAR pages 8B-1 and 7.6-1 In the LRA, the applicant stated that all electrical and I&C 2.1-25 systems (except meteorological instrumentation and (SBO) security systems) are included within the scope LR. Based on the applicants scoping methodology, the staff understands that the electrical power systems required to cope with the SBO rule (10 CFR 50.63) are included in the scope of LR. For this reason, it is not clear to the staff why the applicant stated in FSAR section 8B, Station Blackout, that no power source is required to support the SBO unit, which is part of the below sentence:

In the event that a single EDG is not available in the Non-SBO Unit, such as during a two train EDG outage, no power is required to support the SBO

Unit, since no common equipment is required in support of the SBO Unit.

Question: Please clarify if any power source (e.g., DC power source) is required to support the systems required to cope with an SBO event in one unit in case both EDGs in the non-SBO unit are unavailable.

Comanche Peak Nuclear Power Plant, Units 1 and 2 License Renewal Application (LRA) Breakout Audit Questions LRA Section 4.2.1 TRP: 59.1 Question LRA Section LRA Page Background / Issue Discussion Question /

Number Request 4.2.1 4.2-3

  • I was not able to find a previous licensing basis is being CPNPP licensing action that cited requested for approval in the WCAP-18124-A. current LRA or when WCAP-18124-A was added to the licensing basis 4.2.1 4.2-3
  • L&C 1 requires additional justification Rev. 0 limitations and for application of the method outside conditions.

the active height of the core.

  • L&C 2 places additional conditions on use of least-squares adjustment.
  • WCAP-18630-NP, Rev. 0, Section 2.3 states that comparison with surveillance CPNPP surveillance capsules were not used to modify calculated surveillance capsule and pressure vessel neutron exposures.

4.2.1 4.2-3

  • The LRA does not contain details of the Provide details of the neutron neutron fluence calculation. fluence calculation on the docket.

Appendix A to

  • Appendix A to WCAP-18630-NP Discussion on whether EVND WCAP-18630-NP provides EVND results. results presented in WCAP-(not presently
  • EVND results for Unit 1 at the core 18630 represent all capsules docketed) midplane, core top, core bottom, RPV irradiated at CPNPP, and how supports, and bottom head, are determinations are made presented. regarding EVND insertion,
  • EVND results for Unit 2 at the core withdrawal, and analysis midplane, core top, and core bottom. schedules.
  • M/C differences for Unit 2, at core bottom, are comparable to M/C differences for Unit 1 , at RPV supports.

Comanche Peak Nuclear Power Plant, Units 1 and 2 License Renewal Application (LRA) Breakout Audit Questions LRA Section 4.2.2 - 4.2.5 /TLAA:

Question LRA/SLRA Section LRA/SLRA Background / Issue Discussion Question /

Number Page Request (As applicable/needed) 1 LRA Section 4.2 -

  • Copper and nickel for the Identify any additional Tables with material BELTLINE material is discrepancies for Cu, Ni and property values for slightly different that the RTndt (U) - if any Cu and Ni values in FSAR Chapter 5
  • I understand that the values in LRA match the information Can the licensee discuss the provided in the SPU LAR in basis for these slight 2008/2009 timeframe - but changes/variations between there wasnt a discussion the FSAR and LRA that I was able to find that explained the slight variations in these material What was the basis for the property values from FSAR revision in values??

and SPU/LRA.

  • Example for Unit 1 - not all inclusive
  • Materials R1107-1, -2 and -3
  • FSAR Cu - 0.06, 0 .06, 0.05, respectively
  • LRA Cu - 0.07, 0.07, 0.06, respectively 2
  • Initial USE - LRA Table 4.2.3- Are there any other 1 discrepancies?

EXAMPLES (not all inclusive)

  • Unit 1 - Beltline region weld Discuss why there is a metal (heat # 88112) - discrepancy between the footnote a cited FSAR table LRA and FSAR -

5.3-2A for initial values

  • Initial USE in LRA -133 ft-lbs If this is related to Question
  • FSAR Table - 150 ft-lbs #1 - please address together.
  • Unit 1 - Lower Shell Plate 1108 footnote a cited FSAR table 5.3-2A for initial values
  • Initial USE in LRA - 85 ft-lbs
  • FSAR Table - 84.5 ft-lbs
  • Unit 1 - Intermediate Shell R1107-1
  • Initial USE in LRA - 94 ft-lbs
  • FSAR Table - 93.5 ft-lbs There are variations in values reported in LRA and FSAR. I understand that rounding may be the reasoning - but in at least one instance initial USE values in LRA were reported to first decimal place

- So not sure if initial values actually were changed or in some instances there was rounding.

3 LRA identifies upper shell plate as It looks like they are the R-3806-1, -2 and -3 same material - if so, why the difference in UFSAR identifies is what appears to naming/identification?

be the same materials with A designation.

4 WCAP 18630-NP Foot note d - copper and nickel from Discussion as to how these CE-NPSD-1119- table 5 - initial values were determined for materials that

  • Intermediate Shell cited CE Report LD-79-036 longitudinal weld seams 101-124A, B and C (heat#

89833)

Provide CE Report LD

  • Lower shell long weld seams 036 101-142 A, B and C (heat#

89833)

  • Intermediate to Lower shell Since the cited reports are girth weld seam 101-171 relatively old, has any effort (heat # 89833) been made to see if there is any recent information that
  • Upper Shell to Intermediate is applicable to these shell girth weld seam 103- materials?

121 (heat# 3P7317)

CE Report LD-79-036 - Report was cited as the basis for Copper and If not, does there need to be Nickel for Upper Shell Longitudinal  ?

Weld Seams 101-122 A, B and C Question 4 and 5 can be (heat# 89827) addressed together CE-NSPD-1119 is over 20 years old and CE Report LD-79-036 is over 40 years old

5 WCAP 18630-NP - Table 3-1 and 3- Discussion as to how these 2 - both materials for BOTH units- initial values were Related to initial USE values determined for materials that cited CE Report LD-79-036

  • Upper Shell to Intermediate Shell Girth Weld Seam 103-121 Provide CE Report LD
  • Upper Shell Longitudinal 036 Weld Seam 101-122 A, B and C Since the cited report is relatively old, has any effort

- cited as the basis initial any recent information that USE values is applicable to these materials?

Unit 1 If not, does there need to be

  • Upper Shell Plate to  ?

Intermediate Shell girth weld seam 103-121 (HT# 90149) Question 4 and 5 can be addressed together

  • Basis for initial value of 144 ft-lbs
  • Upper Shell Longitudinal Wels Seams 101-122A, B and C
  • Basis for initial value of 197 ft-lbs Unit 2
  • Upper Shell to Intermediate Shell Girth Weld 103-121 (HT# 3P7317)
  • Basis for initial value of 99 ft-lbs
  • Upper Shell Longitudinal Weld Seams 101-122A, B and C (HT# 89827)
  • Basis for initial value of 142 ft-lbs 6 Unit 1 - Upper Shell Longitudinal Does WCAP-18607 have Weld Seams 101-122 A, B and C the credibility evaluation for (heat #4P6052) both Millstone and Seabrook surveillance data?

LRA Table 4.2.2 Footnote f -

does not discuss/reference the Provide a quick summary of credibility evaluation for this the credibility evaluation in material WCAP-18607 WCAP-18630 - NP - Section B.2 Please provide WCAP-indicates that this material is the 18607 - NP and/or any same from Seabrook, Unit 1, and other document that Millstone, Unit 3 contains the credibility evaluation for this material WCAP-18607 - NP was cited as from Seabrook, Unit 1, and having the credibility evaluation for Millstone, Unit 3 this material Provide a quick summary of the credibility evaluation in WCAP-18607 or whichever document contains the evaluation.

7 Unit 2 - Upper Shell to Intermediate Which plant is the Shell Girth Weld 103-121 (HT# surveillance weld from 3P7317)  ? Palo Verde? Or Millstone?

LRA Table 4.2.2 Footnote f -

does not discuss/reference the Please provide WCAP-credibility evaluation for this 16524 - NP and/or any material other document that contains the credibility WCAP-18630 - NP - Section B.2 evaluation for this material indicates that this material is the from Palo Verde Unit 2 and/r same from Palo Verde unit 2 Millstone Unit 3 - which ever WCAP-16524 - NP was cited as plant(s) the surveillance having the credibility evaluation for weld is from this material Provide a quick summary of Table 5-5 of WCAP-18630 identifies the credibility evaluation in that the surveillance weld is from WCAP-16524 or whichever Millstone 3 - this is different from the document contains the Table 5-3 and Appendix B of WCAP- evaluation.

18630 (i.e., surveillance weld is from Palo Verde) 8 LRA Section 4.2.5 - Dispositioned in accordance with (iii) It appears that Comanche PT limits - Peak has been approved for PTLR - If this is true, why LRA states The effects of aging on would ART values need to the intended function(s) of the be submitted for NRC review reactor vessels will be adequately and approval? Is there managed for the PEO. The Reactor something unique for Vessel Surveillance AMP described Comanche with the PTLR in B.2.3.18 will ensure that updated approval ?

P-T limits based upon updated ART values will be submitted to the NRC for approval prior to exceeding the current terms of applicability of With a PTLR - Why would CPNPP Units 1 and 2. PT limits need to be

submitted to the NRC for review and approval?

Didnt see anything in PTLR approval in 2007 and TS 5.6.6

Comanche Peak Nuclear Power Plant, Units 1 and 2 License Renewal Application (LRA) Breakout Audit Questions LRA Section /AMP/B2.3.7 PWR Vessel Internals Question LRA LRA Background / Issue Discussion Question / Request Number Section Page 1 AMP LRA Page B-57 of the AMP states PWR Owners Group (1)Discuss how Item W14 in Table 4-9 of MRP-B2.3.7 (PWROG) issued guidance OG-21-160 to address clevis 227, Rev. 1-A will be implemented during the Page B- insert degradations. The PWROG-referenced guidance period of extended operation for the CPNPP units 57 and B- is new guidance of how to perform ultrasonic test (UT) and the scope of supplemental Westinghouse or 58 inspections of the clevis insert bolts. PWROG guidance that will be implemented under the inspection and evaluation (I&E) criteria The current aging management basis for clevis insert of Item W14 in Table 4-9 of MRP-227, Rev 1-A.

bolts and wear surfaces in Item W14 in Table 4-9 of MRP-227, Rev. 1-A only calls for ASME Section XI VT-3 (2) If the guidance in OG-21-160 will be visual inspections of the clevis insert bolts and wear implemented in addition to Westinghouse Bulletin surfaces, as modified by the VT-3 criteria in No. TB-14-5, discuss whether OG-21-160 will be Westinghouse Bulletin No. TB-14-5. Item W14 in Table identified as an Enhancement of Item W14 in 4-9 of MRP-277, Rev. 1-A does not include or reference Table 4-9 of MRP-227, Rev. 1-A and an use of PWROG guidance OG-21-160 (although the staff Enhancement as part of AMP B2.3.7.

acknowledges that use of the OG-21-160 guidance was added to Item W14 in Table 4-9 of MRP-227, Rev. 2, which is under the staff review at present).

2 AMP LRA In the Operating Experience section of AMP B 2.3.7, the (1)Discuss whether the fuel alignment pins in the applicant discussed industry operating experience of upper and lower reactor internal assemblies at B2.3.7 Pages upper and lower assembly fuel alignment pins. The CPNPP units are designed as ASME Section XI B-58 to applicable generic operating experience is associated Examination Category B-N-3 components. If so, with U.S. reports of detected surface breaking discuss whether the ASME Section XI inspection B-59 indications induced by wear in the pins of another will be performed on the alignment pins nuclear plant. The applicant states that regardless of the fact that the alignment pins do recommendations for managing wear in the pins is given not include a malcomized surface that would

in Westinghouse Bulletin TB-14-6, but clarifies that the make them susceptible to wear. (2) Discuss guidance only applies to the fuel alignment pins made whether the design of the alignment pins at from Type 304 stainless steel with a malcomized surface CPNPP are susceptible to cracking based on the treatment. The applicant states that this operating cold working of the 316 SS materials that were experience is not applicable to CPNPP because the fuel used in fabrications of the alignment pins.

alignment pins at CPNPP are made of cold-worked Type 316 stainless steel (316 SS).

The staff notes that MRP-227, Rev. 1-A is not to be used as a replacement for implementing ASME Section XI inspections of reactor vessel internal components that are designated as ASME Code Class Internal components in the current licensing basis (CLB).

3 AMP LRA Inspections of Westinghouse-design control rod guide Discuss CRGT guide card inspections and the B2.3.7 Page tube (CRGT) guide plates (guide cards) are covered by results of past inspections performed on the Unit Item W1 in Tables 4-3 and 5-3 of MRP-227, Rev. 1-A. 1 CRGT guide cards, including the following B-60 The fourth paragraph on LRA page B-60 states that questions:

during the Spring 2022 outage, all 53 Unit 1 guide tubes and associated guide cards were inspected and 1) For CPNPP units, are there applicable measured for wear based Expansion components for the CRGT guide cards in the AMP? If so, identify the linked on guidance in WCAP-17451, Revision 1. The applicant Expansion-category components for the Primary stated that the low wear levels were observed at Unit 1. category CRGT guide cards in the AMP.

The applicant further stated that it will inspect Unit 2 guide cards in Spring 2023. 2) If there are applicable Expansion category components for the CRGT guide cards, was the Item W1 in Tables 4-3 and 5-3 of MRP-227, Rev. 1-A degree of wear detected from the Unit 1 includes the CRGT guide cards as Primary category inspections sufficient to call for sample-expansion components that are subject to VT-3 visual inspections to the lined CRGT Expansion-category for wear-type flaw indications, without any designated or component types?

linked Expansion category components. Item W1 indicates that the inspections are done per the guidance in Proprietary Report WCAP-17451, Rev. 1. However, contrary to Item W1 in Table 4-3 of MRP-227, Rev. 1-A, the proprietary guidance in WCAP-17451, Rev. 1 indicates that there are two types of Westinghouse CRGT assembly components that serve as Expansion,

instead of being Primary, components for Westinghouse-design CRGT guide cards.

4 AMP LRA Page B-61 discusses operating experience with PWR The re-inspection for the thermal sleeve flange B2.3.7 Page RPV nozzle thermal sleeves at the flange locations per wear at Unit 2 is 6 cycles but for Unit 1 the NSAL-18-01, NSAL-20-01, Rev. 1, and MRP-2018-027 reinspection is 12 cycles. Confirm whether Unit 1 B-61 guidelines. The third paragraph on page B-61 of the has a longer re-inspection interval because Unit 1 CPNPP LRA states that At CPNPP, baseline has a new RPV head which has not had inspections were completed during the Fall 2021 outage significant wear at the thermal sleeve flange.

for Unit 2. Normal wear was found during visual inspections with a recommendation to re-inspect within 6 cycles. Baseline inspections for Unit 1 were completed during the Spring 2022 outage, also showing normal wear with a recommendation to re-inspect in 12 cycles 5 AMP LRA In MRP-277, Rev. 1-A, Table 4-6, the core barrel (CB) (1)Considering recent operating experience of the B2.3.7 assembly upper girth weld (UGW) is established as an degraded UGW in the CB in a PWR plant, Pages B- Expansion-category Item W3.1 weld for the linked discuss whether CPNPP will inspect the CB 63 and Primary-category Item W3 upper flange weld (UFW) in UGWs in the near future, as the CB UGWs are top B-64 Table 4-3 of MRP-227, Rev. 1-A. The NRC staff notes currently designated as an Expansion-category that, recently, the licensee for a U.S. Westinghouse- welds for the CPNPP units. (2) Discuss whether design nuclear plant detected several circumferential the CB UFWs and UGWs are designated as flaws in the UGW of the units CB assembly during the ASME Section XI Examination Category B-N-3 fall 2022 refueling outage. Some of the flaws were weld for the CB assemblies. If so, discuss reported to have significant depths with respect to the whether past ASME Section XI VT-3 inspections weld wall thickness. of the welds have identified any relevant flaws in the UFWs and UGWs.

6 AMP LRA The applicant stated that The PWR Vessel Internals (1)Confirm that AMP B2.3.7 follows the version of B2.3.7 AMP will be consistent with NUREG-1801, Section AMP XI.M16A in the SLR-ISG-2021-01-PWRVI, Page XI.M16A, PWR Vessel Internals, as superseded by without the need of an RVI gap analysis.

B-57 SLR-ISG-2021-01-PWRVI . The NRC staff notes that NUREG-1801 is not superseded by SLR-ISG-2021 (2) Confirm that Revision 2 of NUREG-1801 will PWRVI, rather SLR-ISG-2021-01-PWRVI provides be used in the AMP.

update to NUREG-1801. It is not clear whether the AMP will be consistent with SLR-ISG-2021-01-PWRVI. In

addition, NUREG-1801 has two revisions, Revisions 1 and 2. It is not clear which revision will be used.

Comanche Peak Nuclear Power Plant, Units 1 and 2 License Renewal Application (LRA) Breakout Audit Questions LRA Section B.2.3.3 Reactor Head Closure Stud Bolting Question LRA LRA Background / Issue Discussion Question /

Number Section Page Request (As applicable/needed) 1 4.7.3 4.7-4 Section 4.7.3 describes a series of NRC- Confirm the following, based through - approved topic reports that support a 20- upon the referenced SE:

6 year inspection interval for the RCP flywheel. The appropriate staff SE

  • the normal operating (ML19198A056) states that applicants speed for the RCP implementing this methodology to justify a flywheels is 900 rpm 20-year inspection interval should confirm
  • the design limiting speed that several aspects of the underlying for the RCP flywheels is analysis are applicable to the applicant. 1125 rpm
  • it is appropriate to use 70°F as the medium temperature for design limiting event (Table 3-2) in the PFM analysis
  • 6000 start/stop cycles is bounding

Comanche Peak Nuclear Power Plant, Units 1 and 2 License Renewal Application (LRA) Breakout Audit Questions LRA Section/AMP: XI.M37 Flux Thimble Tube Inspection Question LRA LRA Background / Issue Discussion Question /

Number Section Page Request (As applicable/needed) 1 Program Page Scope of program element provides references to the applicant response to Was there an NRC Basis 10 of NRC Bulletin 88-09. Reference 9.9 provides the NRC response to Unit 1. response for Unit 2 document - 21 actions related to NRC Section 4.1 For unit 1 - it looks like the NRC letter was issued 2 months after the initial Bulletin 88-09?

scope of inspection results were submitted to the NRC (letter dated Dec 20, 1991) program element

Unit 2 initial inspection results submitted November 7 1994 - ML20078E542 2 Program Page Monitoring and trending element discusses the use of WCAP 12866. It also

  • Provide WCAP-Basis 12 of discusses that this methodology has sufficient conservatism. 12866 for review document - 21 during audit.

Section 4.5 WCAP-12866 has been not approved by the NRC generically monitoring

  • Provide discussion and of the projection trending methodology in element WCAP-12688 and its use in CPNPP -

including discussion of the sufficient conservatism mentioned in the program basis document.

  • Has any other projection methodology been used at CPNPP? If so, please describe and why the switch to WCAP-12866
  • How well has WCAP-12866 projected wear to-date? Has there

been any issues/anomalies with the projections where the predictions were non-conservative?

  • Portal contains inspection results for last two inspections at each units - Can results from the two prior inspections from each unit also be provided.

3 LRA Section LRA LRA states Due to the potential thinning of flux thimble tubes as reported in

  • Discuss the B.2.3.23 - Page NRC IEB 88-09 CPNPP commenced examinations of the flux thimble tubes at discrepancy Operating B- CPNPP Unit 1 and Unit 2 using eddy current examination in 1991. Flux between Experience 148 thimble tubes are presently examined each refueling outage and Eddy documents and Section current inspection results of flux thimble tubes for the last two outages of the inspection each unit were reviewed. frequency.
  • So currently

& inspections at Program Basis document states Flux thimble tubes are presently examined each unit are done every other refueling outage (every 3 years) - each outage or Program ^^this is consistent with the PM349506 and PM349507 every other outage basis &

regardless of the document - projected wear Section 4.4 (except if the Detection Page thimble tube wont of Aging 11 of make it to next 21 inspection)? (i.e.,

Effects inspection element frequency/intervals are not extended for longer than the set periodicity?)

4 Program Page Program basis document states that CPNPP is participating in a PWR

  • Provide basis 9 of Owners Group project to examine the historical eddy current results with description of this document - 21 hopes to extend the interval between inspections effort - what does Discussion it entail, status, of RAIs from results, etc?

other LRA/SLRA

  • Is this going to only look at plant-specific results to extend the inspection intervals? If not, additional discussion of this effort would be helpful.
  • Currently, is the extension of inspection intervals based on plant-specific results prohibited?

5 Program Page Program element 6 of XI.M37 states: Acceptance criteria different from those

  • Was the use of basis 12 of previously documented in the applicants response to IE Bulletin 88-09 and WCAP-12866 at document - 21 amendments thereto, as accepted by the NRC, should be justified. CPNPP previously Section 4.6 approved as part

- Program basis document states - wear acceptance criteria have been of the response to Acceptance established, using the guidance of WCAP-12866 NRC Bulletin 88-09? (the CPNPP response to

Criteria Program basis documents also discusses action levels started at 20% Bulletin 88-09 in element through-wall wear until 80% through-wall wear - and references MRS-GEN- ML19327B845 1180 (levels mentioned as part of calibration/standard in Section 7). This doesnt provide the document did not appear to discuss the actions taken for each of these levels details)?

  • Provide discussion of the different actions taken based on the action levels discussed in the Program Basis document (i.e.,

10%, 20% all the way through 80%).

  • Do these action levels also equate to when thimble tubes are capped, move/repositioned, removed/replaced, etc?? - If not how/when is this decision made?
  • Where is this currently documented on what actions are going to be taken based on through wall wear percent? - Didnt see it in the PM 349506, 349507,

TPVEN_MRS-GEN 1180 and 1304

Comanche Peak Nuclear Power Plant, Units 1 and 2 License Renewal Application (LRA) Breakout Audit Questions LRA Section B.2.3.3 Reactor Head Closure Stud Bolting Question LRA LRA Background / Issue Discussion Question / Request Number Section Page (As applicable/needed) 1 B.2.3.3 See CR-2019-003497/EV- CR-2019-003497-1 discusses the Have you checked in subsequent outages cited presence of demineralized water (for use as UT couplant) in that there is no more water? Has there CR/EV- stud holes. This CR/CR-EV fully described the situation and been any occurrences of this since 2019 (or CR stated that the water will evaporate. was this a one-off situation)?

2 B.2.3.3 B-40 Regarding: ISI exam reports Clarify Geometric indication (sleeve) seen 360° around stud hole #6. The indication 1RF20 ISI Report.pdf includes: exceeded 20% DAC but did not exceed ISI exam sheet for B-G-1 B6.40 (threads in flange) states that 50% DAC.

Geometric indication (sleeve) seen 360° around stud hole

  1. 6. The indication exceeded 20% DAC but did not exceed 50%

DAC.

3 B.2.3.3 B-40 The last operating experience in LRA Section B.2.3.3 states What was the issue with the HydraNuts?

that outage delays occurred due to HydraNuts. CR-2013-000912 was created to indicate that HydraNuts have been replaced with original nuts.

4 B.2.3.3 B-40 CR-2017-004534 says that in 2RF16, Stud #32 of Unit 2 was Neither CR-2017-004534 nor the LRA determined that it could not be removed, i.e., it was stuck. provide information regarding the resolution of stuck Stud #32 in 2RF16. Can you describe the resolution to the stuck Stud

  1. 32 in 2RF16?

5 B.2.3.3 B-40 Questions #5 through #10 pertain to the damaged threads a. Is the damage just in the stud hole or described as one of the operating experiences in LRA Section also in the studs themselves?

B.2.3.3 that occurred in July 2014. The staff would like to understand contributors to this particular OE and ensure that it b. With respect to the flange upper surface, is being adequately managed. where is the approximate location of the damaged threads?

6 B.2.3.3 B-40 See #5 above a. What were the factors that contributed to the thread damage and applicants corrective actions, per 10 CFR 50 Appendix B via Element 7 of XI.M3 AMP, to prevent such damage in the future?

b. If due to high tensioning loads, is there a limit placed on tensioning loads in the procedures (MSM-C1-9901 and MSM-C2-9901)?

7 B.2.3.3 B-40 See #5 above How many studs are used to tension per unit and how many studs/holes were damaged at each unit?

8 B.2.3.3 B-40 See #5 above a. Were the damaged stud holes repaired and/or damaged studs replaced?

b. The LRA states that the ISI program will continue to monitor these locations; has the number of damaged threads increased for any stud hole with damaged threads, especially the one stud hole with 13.75 damaged threads since 2014?
c. Has there been any new thread damage since 2014?

9 B.2.3.3 B-40 See #5 above a. Is thread damage related to stuck studs, ie, any evidence that damage and being stuck are correlated?

b. Is there a potential corrosion effect on the stuck/damaged studs especially during refueling outages?

10 B.2.3.3 B-40 See #5 above a. Is 13.75 threads the highest number of damaged threads from both units?

b. Regarding the allowable damaged threads of 17.22: is there a limit on tension/detension cycles?

Comanche Peak Nuclear Power Plant, Units 1 and 2 License Renewal Application (LRA) Breakout Audit Questions LRA Section /AMR/PWR Vessel Internals Question LRA LRA Background / Issue Discussion Question / Request Number Section Page 1 Table 3.1.2- LRA Items IV.B2.RP-345a and IV.B2.R-424 in Table 3.1.2-2 on Discuss the discrepancy on AMR items and 2 page page 3.1-83 are identified as bottom mounted instrumentation AMP bases for the non-pressure boundary (BMI) flux thimble tubes with Notes C, D, and E. These two portions of the flux thimble tubes that are 3.1-83 items are correlated to aging effects of SLR-ISG-2021 located inside the RPV (i.e., noting that the PWRVI Item IV.B2.RP-345a, GALL-SLR Items IV.B2.R-345 pressure boundary portions of the thimble and R-424 such as loss of fracture toughness due to tubes are adequately covered by applicable (pdf page irradiation embrittlement (IE), loss of material due to wear, line items in LRA Table 3.1.2-1 on page 3.1-410) change of dimensions to void swelling (VS) or distortion, and 62.

loss of preload due to irradiation-assisted stress relaxation or creep (ISR/IC).

These line items apply to the reactor vessel internal portion of the thimble tubes which are not reactor coolant pressure boundary. However, the BMI flux thimble tubes extend to the outside of the reactor vessel which become part of pressure boundary and are identified with items IV.A2.RP-28, -154 and -

284 in Table 3.1.2-1 (page 3.1-62).

The aging effects for thimble tubes outside of the RPV are different from the thimble tube that are inside of the RPV. LRA Section 3.1.2.2.9, page 3.1-13, indicates that the internal, non-reactor coolant pressure boundary portions of the flux thimble tubes are No Additional Measures components per MRP-227, Rev. 1-A as linked to SRP-SLR Table 3.1-1, Item 3.1-1, 055c and GALL-SLR Item IV.B2.RP-265.

Thus, it appears that a discrepancy exists regarding (1) which line item or items should be used for the PWR vessel internals portions of the flux thimble per LRA Section 3.1.2.2.9 and

those cited for the flux thimble tube non-pressure boundary portions in Table 3.1.2-2, and (2) whether the PWR vessel internal, non-pressure boundary portions of the BMI flux thimble tubes are being subject to MRP-227 aging management activities (i.e., condition monitoring inspections).

2 Table 3.1.2- LRA Table 3.1.2-2, page 3.1-96, includes line items, IV.B2.RP-289 Confirm that the aging effect of cracking on 2 page and RP-345 on cracking of the core barrel flanges that align to core barrel flanges associated with line item GALL-SLR Item IV.B2.RP-289 using either Note C or D. IV.B2.RP-289 is included in Table 3.1.2-2 on 3.1-83 However, the applicable and corresponding Item IV.B2.RP-289 page 3.1-83 such that the item is aligned in SLR-ISG-2021-01-PWRVI applies specifically to MRP-227 with Item IV.B2.RP-289 in SLR-ISG-2021-Existing Program bases for Westinghouse-design lower core 01-PWRVI for the ASME Section XI, VT-3 (pdf page plates or extra-long (XL) lower core plates, where the plates visual inspections that will be applied to the 410) are subject to ASME Code Section XI VT-3 visual inspections Existing Program category CPNPP core for cracking per Item W12.a in Table 4-9 of MRP-227, Rev. 1-A barrel flanges per Item W10 in MRP-227, and for loss of material due to wear per Item W12.b in Table 4- Rev. 1-A.

9 of MRP-227, Rev.1-A. The GALL-SLR report (as updated inclusive of changes made in SLR-ISG-2021-01-PWRVI) does not include an applicable AMR item for cracking of core barrel flanges.

3 Table 3.1.2- LRA Table 3.1.2-2, page 3.1-96 includes line items for neutron Discuss the discrepancies on the AMR 2 page shield panel support pins that align to GALL-SLR Items items provided for neutron shield panel IV.B2.RP-271 and RP-272 using Note C or D. These line supports pins on LRA page 3.1-96.

3.1-96 items are included in Table 3.1.2-2 to manage irradiation-assisted stress corrosion cracking (IASCC) and fatigue Specifically, discuss the following questions induced cracking, loss of material due to wear, loss of preload related to the AMR line items for the neutron (pdf page due to irradiation-assisted stress relaxation or creep (ISR/IC), shield panel support pins:

423) and loss of fracture toughness due to irradiation embrittlement 1) Are the referenced AMR line items for the (IE) in the pins. neutron shield panel support pins will be The referenced GALL-SLR IV.B2.RP-271 and IV.B2.RP-272 subject to augmented, Primary category items apply to management of applicable cracking, loss of inspections per a plant-specific adjustment preload, loss of fracture, changes in dimensions, and loss of of the MRP-227, Rev. 1-A protocols?

material mechanism in Primary category Westinghouse-design baffle-to-former (BF) bolts using GALL/GALL-SLR AMP

XI.M16A, where the bolts are subject to augmented aging 2) If the neutron shield panel support pins management inspections per Item W9 in Table 4-3 of the are justified for placement in the No MRP-227, Rev. 1-A report. Additional Measures category of AMP B2.3.7, PWR Vessel Internals Program, The LRAs adoption of the referenced RP-271 and RP-272 discuss why isnt Table 3.1.2-2 giving a items under Note C or D bases could only be applied to the single line item for the neutron shield panel neutron shield panel support pins if the pins were subject to support pins that aligns to SRP-SLR Table augmented Primary item inspections in the manner that 3.1-1, Item 3.1-1, 055c and GALL-SLR Item Primary category ultrasonic test (UT) inspections are applied IV.B2.RP-265?

to and performed on Westinghouse-design baffle former bolts per Item W9 in Table 4-3 of MRP-227, Rev. 1-A.

Instead, in MRP-227, Rev. 1-A, all neutron shield panel components are placed in the No Additional Measures of the program because the pins do not screen-in for any aging effects per MRP-227, Rev. 1-A.

4 Table 3.1.2- LRA Table 3.1.2-2 includes line items for radial support keys and Discuss Note C or D-related AMR line items 2 page 3.1- associated bolts that align to either GALL-SLR Items for radial support keys and associated bolts 97 IV.B2.RP-285 or RP-399 using Note C or D. These line items in Table 3.1.2-2, page 3.1-97. Specifically, are included in Table 3.1.2-2 to manage IASCC and fatigue confirm whether the proposed AMR line induced cracking, changes in dimension due to void swelling items are conservatively being included in (pdf page (VS) or distortion, loss of material due to wear, loss of preload Table 3.1.2-2. page 3.1-97, to add in the 424) due to irradiation-assisted stress relaxation or creep (ISR/IC), radial support keys and associated bolts as and loss of fracture toughness due to irradiation embrittlement ASME Code Section XI-based Existing (IE) in the radial support key components. Program components for the AMP B2.3.7, PWR Vessel Internals Program and the The cross-referenced GALL-SLR items IV.B2.RP-285 and RP- referenced aging effects, such that Table 399 items apply to aging management of cracking due to 3.1.2-2 is consistent with Item W20 of Table stress corrosion cracking or fatigue, loss of material due to 4-9 in MRP-227, Rev. 2.

wear, and loss of preload due to ISR/IC (bolts only) in reactor pressure vessel interfacing clevis insert assembly components, including bolts or screws, dowels, and clevis insert surfaces, where the GALL-SLR based line item calls out the ASME Code,Section XI inspection-based Existing Program criteria in Item W14 of Table 4-9 in MRP-227, Rev. 1-A for the clevis component types.

The GALL Rev. 2 and GALL-SLR reports do not include a similar Existing Program-based AMR line items for the radial support key components. However, the EPRI MRP added the radial support keys in as new Existing Program components in the newly submitted MRP-227, Rev. 2 report through inclusion of the component type in newly proposed Item W20 of Table 4-9 in MRP-227, Rev. 2.

5 Table 3.1.2- LRA Table 3.1.2-2, page 3.1-98, includes two line items for the (1)Discuss Note C or D-related AMR line 2 page upper internals assembly (UIA) support ring that aligns to Item items for the UIA support rings on page 3.1-IV.B2.RP-288 using Note C. These line items are included in 98. Specifically, confirm whether the 3.1-98 Table 3.1.2-2 to manage loss of fracture toughness due to proposed AMR line items are conservatively irradiation embrittlement (IE) and loss of material due to wear being included in Table 3.1-2, page 3.1-98, in the UIA support rings. to add loss of fracture toughness and loss (pdf page of material due to wear as aging effects (i.e, 425) The cross-referenced item IV.B2.RP-288 in SLR-ISG-2021 in addition to cracking) for the ASME PWRVI applies to aging management of loss of material due Section XI-based Existing Program criteria to wear, and loss of fracture toughness due to IE, and for the UIA support rings that are aligned to changes in dimension due to void swelling (VS) or distortion in Item W11 of Table 4-9 in MRP-227, Rev. 1-Westinghouse-design lower core plates or extra-long (XL) A.

lower core plates.

(2) Discuss whether the RP-288 based line items for UIA support ring in Table 3.1.2-2 need to include an associated AMR line item on aging management of changes in dimension due to void swelling or distortion in the UIA support rings to be consistent with item IV.B2.RP-288 in SLR-ISG-2021-01-PWRVI .

6 Table 3.1.2- LRA Table 3.1.2-2, pages 3.1-91 to 3.1-96, includes a number of (1)Discuss any unit-specific differences 2 pages AMR line items for lower support columns and associated between the design of the lower support column components that align to GALL-SLR Item IV.B2.RP- columns and associated components in Unit 3.1 290 (for non-cracking effects) or IV.B2,RP-291 (for cracking) 1 from those that are included in Unit 2. (2) 3.1-96 using Note A or B. These items correspond to Expansion Item If applicable, discuss whether those design W4.4 in Table 4-6 of MRP-227, Rev 1-A. differences will cause any adjustments of the MRP-227, Rev. 1-A inspection and

(pdf However, the line item entries in Table 3.1.2-2 differentiate evaluation protocols for Expansion pages between the lower support column components in Unit 1 and Category Item W4.4 lower support columns 418 - Unit 2. (independent of whether the columns are 423) made from either cast austenitic stainless steel materials or wrought stainless steel materials).

7 Table 3.1.2- LRA AMR line item IV.B2.RP-386 in GALL, Rev. 2 (pdf page 249) Discuss why Table 3.1.2-2 does not include 2 covers management of loss of material due to wear in any AMR item or items for managing loss of Pages Westinghouse-design control rod guide tube (CRGT) C-tubes material due to wear in the CRGT C-tubes 3.1-85 and sheaths. Although Table 3.1.2-2, pages 3.1-85 to 3.1-86 and sheaths. Specifically, discuss why the includes corresponding line items for aging management of CRGT C-tubes and sheaths are not To loss of material due to wear of CRGT that corresponds to included within the scope of the line item on Primary Item W1 CRGT guide plates (i.e., CRGT guide cards), loss of material due to wear for the CRGT 3.1-86 Table 3.1.2-2 does not include corresponding AMR items for guide cards that is aligned to Item the CRGT C-tubes and sheaths. IV.B2.RP-296 in Table 3.1.2-2 on page 3.1-86.

8 Table 3.1.2- N/A Table 3.1.2-2 does not include any component-specific AMR Discuss how the CRGT split pins are being 2 line items for control rod guide tube (CRGT) support pins (spilt managed for cracking consistent pins) that are included in the CPNPP unit-specific CRGT with criteria defined in the GALL-SLR assembly designs. In Table 3.1-1, Item 028 of SLR-ISG-2021- Item column entry of Table 3.1-1, Item 028, 01-PWRVI, the basis for managing Westinghouse-design of SLR-ISG-2021-01-PWRVI.

CRGT spilt pins was dependent on whether the pins were: (1) made from X-750 nickel-based alloy materials (versus Type Discuss the following design basis for the 316 stainless steel materials), and whether the spilt pins were CRGT spilt pins: (1) material of fabrication Examination Category B-N-3 components of Table IWB-2500- for the pins in both units, (2) whether the 1 of the ASME Code,Section XI where the ASME Section XI CRGT spilt pins in both units are original inspections would be credited for aging management of pins or replacement pins, (3) whether the cracking in the pins. CRGT spilt pins are defined in the CPNPP design basis that required to be inspected In Table 3.1-1 of SLR-ISG-2021-01-PWRVI, Item 3.1-1, 028, periodically under Examination Category B-replacement CRGT split pins made from type 316 stainless N-3 of Table IWB-2500-1 of the ASME pins (and not subject to ASME Code Class inspections Code,Section XI, and (4) if the pins are credited for aging management) were permitted to be placed ASME Code Class components, discuss in the No Additional Measures category consistent with the whether the ASME Section XI inspections

criteria established for CRGT spilt pins in MRP-227, Rev. 1-A. scheduled for the CRGT spilt pins are being The staff notes that this is predicated on the condition that, if credited for aging management of cracking CRGT spilt pins are ASME Code Class pins, the ASME in the pins per the AMP B.2.3.1, ASME Section XI inspections of the pins are not credited for Existing Section XI ISI Program versus ASME-based Program credit in MRP-227, Rev.1-A such that the ASME Existing Program basis in the AMP B.2.3.7, inspections of the pins would be credited under the applicants PWR Vessel Internals Program.

AMP B.2.3.1 ISI Program per GALL Item IV.E.R-444 in the SLR-ISG-2021-01-PWRVI.

Comanche Peak Nuclear Power Plant, Units 1 and 2 License Renewal Application (LRA) Breakout Audit Questions LRA Section B.2.3.18, Reactor Surveillance AMP Question LRA/SLRA LRA/SLRA Background / Issue Discussion Question / Request Number Section Page (As applicable/needed) 1 LRA Section LRA Page B-

  • Unit 1 - Capsule Z reinserted prior to
  • What is the current best-estimate B.2.3.18 - 126-127 36EFPY - need additional 9EFPY - to approximate calendar year that the Program get 80 EFPY fluence. capsule for each unit will be inserted Description back into the reactor vessel at 36
  • Capsule W and V - can also be used - EFPY - for both units 13 additional EPFY
  • What is the current best-estimate
  • Unit 2 - Capsule Z reinserted prior to approximate calendar year that the 36EFPY - need additional 8EFPY - to capsules for each unit will be get 80 EFPY fluence. withdrawn after the needed exposure in
  • Capsule Y and V - can also be used - the reactor (Unit 1 - Capsule Z, W and 14 additional EPFY V) and (Unit 2 - Capsule Z, Y and V)
  • Enhancement to Element 4 states: A
  • Given responses to above questions -

capsule in each unit will be reinserted provide discussion regarding lack of prior to 36 EFPY in order to achieve at detail in LRA (Appendix A and B) for least a vessel equivalent fluence of 80 enhancement to element 4, Detection EFPY. of Aging Effects for the capsule withdrawal schedule

  • The Enhancement and UFSAR Supplement (A.2.2.18) is very open ended - there needs to be some level of regulatory certainty regarding what/when is being credited for aging management (i.e., which capsule at what time)

Section III.B.3 states A proposed withdrawal schedule must be submitted with a technical justification as specified in § 50.4. The proposed schedule must be approved prior to implementation.

2 LRA Section LRA Page B-

  • Enhancement to Element 4 and 7
  • Where is the latest information for B.2.3.18 - 127-128 states: The capsule withdrawal capsule Enhancements schedule will be documented in the schedule/fluence/EFPY/lead factor\etc, PTLR and note that changes require info be found? -

NRC approval per 10 CFR 50, Appendix H.

  • Provide document on portal - is this document publicly available (i.e., been
  • FSAR section 5.3.1.6.1 states The submitted to the NRC and in ADAMs) -

schedule for removal of the capsules latest document I was able to find were for post-irradiation testing is found in capsule reports when they were Section 2.4 of PTLR for the respective submitted per Appendix H in the 2000 units. timeframe.

  • Discuss the thinking/rationale for states A withdrawal schedule for Units needing this enhancement? Seems 1 and 2 are not necessary, because all like the FSAR/PTLR has provisions Units 1 and 2 surveillance capsules related to a capsule withdrawal have been withdrawn from the reactor schedule.

vessel.

3 LRA Section LRA Page B-

  • Operating experience example for July
  • Can you explain the situation - from B.2.3.18 - 128-129 2019 - indicates that PTLR needed to LRA it looks like capsule data was Operating be updated to include data from latest never incorporated/assessed into the Experience capsule withdrawal (unit 1 - 2005 and PTLR until 2020/2021.

Unit 2 -2009)

  • Its not clear how this situation was
  • LRA Section B.2.3.18 states - administrative - when Appendix H has Therefore, this is considered reporting requirements related to administrative for the purpose of whether or not PT limits need to be

tracking the revision of the PTLR to revised based on capsule testing - See incorporate the results from the App H - Section IV.C Capsule X (Unit 1) and Capsule W (Unit 2) analysis.

  • So, the PT limits were not assessed to see if the they were impacted by the capsule data for 16 and 12 years for unit 1 and 2, respectively? Provide discussion of circumstances/situation related to OPEX example.

4 LRA Section LRA Page B-

  • Enhancement to Element 4 and 5
  • The temperature range being selected B.2.3.18 - 127-128 states The AMP documents will be - is it from Section 1.3, Limitations of Enhancements modified to establish operating RG 1.99, Rev 2?

restrictions to ensure that the plant is operated within the material aging OE,

  • Considering that this is an i.e., the cold leg operating temperature enhancement (i.e., existing program during normal operation will be limited isnt currently doing it) What is the to 525°F (minimum) to 590°F current operating window CPNPP is (maximum). operating within for the cold leg operating temperature during normal operation
  • What is expected to actually be updated to implement this enhancement - something in the PTLR, Tech specs, internal operating procedure, something else

Comanche Peak Nuclear Power Plant, Units 1 and 2 License Renewal Application (LRA) Breakout Audit Questions LRA Section B.2.2.1, Fatigue Monitoring Question LRA LRA Background / Issue Discussion Question / Request Number Section Page (As applicable/needed) 1 B.2.2.1 B-21 LRA Section B.2.2.1 addresses Enhancement 1 regarding 1. Clarify whether the applicant will submit the scope of the program and preventive actions for the NRC staffs review and approval program elements of the Fatigue Monitoring Aging the 60-year projected CUFen values for Management Program (AMP). the plant-specific sentinel locations (not listed in NUREG/CR-6260) at least a The enhancement states that the program will be modified certain time period (e.g., one year) to include environmentally assisted fatigue (EAF) analyses before entering the period of extended for locations that have been determined to be sentinel operation to demonstrate the locations through the EAF screening evaluation in addition effectiveness of the Fatigue Monitoring to those listed in NUREG/CR-6260. The sentinel locations AMP with no need for additional are also called limiting EAF locations. activities (e.g., flaw tolerance In comparison, LRA Section 4.3.4 addresses the EAF analysis). If so, discuss a potential analyses. Specifically, LRA Tables 4.3.4-1 and 4.3.4-2 need to revise Enhancement 1 of the describe the equipment (component) sentinel locations and program accordingly. If not, provide piping sentinel locations, respectively. These sentinel justification for why such a submittal is locations include those identified for newer vintage not necessary.

Westinghouse plants in NUREG/CR-6260, which are 2. Clarify whether this enhancement also applicable to the Comanche Peak plant, and other sentinel include the monitoring of environmental locations (plant-specific sentinel locations) that may be cumulative usage factor (CUFen) values more limiting than the generic locations identified in to ensure that the CUFen values do not NUREG/CR-6260. exceed the design limit (1.0). If not, With respect to the sentinel locations identified in provide justification for why such NUREG/CR-6260, LRA Tables 4.3.4-1 and 4.3.4-2 provide monitoring is not necessary as part of the 60-year projected environmental cumulative usage Enhancement 1.

factor (CUFen) values. In contrast, Tables 4.3.4-1 and 4.3.4-2 do not provide CUFen values for the sentinel locations other than those identified in NUREG/CR-6260 in relation to

Enhancement 1 of the Fatigue Monitoring AMP (i.e., the enhancement to the program to estimate the CUFen values for these non-NUREG/CR-6260 sentinel locations for the extended period of operation).

However, the staff requests clarification regarding whether the applicant will submit for NRC staffs review and approval the 60-year projected CUFen values for the plant-specific sentinel locations (not listed in NUREG/CR-6260) at least a certain time period (e.g., one year) before entering the period of extended operation to demonstrate the effectiveness of the Fatigue Monitoring AMP with no need for additional activities (e.g., flaw tolerance analysis).

In addition, the staff requests clarification regarding whether this enhancement include the monitoring of CUFen values to ensure the CUFen does not exceed the design limit (1.0).

2 B.2.2.1 B-21 LRA Section B.2.2.1 addresses Enhancement 2 regarding 1. Clarify what parameters will be the preventive actions program element of the Fatigue monitored for environmental effects in Monitoring aging management program (AMP). The the enhancement and what AMP will be enhancement states that the program will be modified, as credited for the monitoring of needed, to monitor the environmental effects at the sentinel environmental effects (e.g., water locations. chemistry parameters such as dissolved oxygen). In addition, clarify whether this It is not clear to the staff what parameters will be monitored enhancement also monitors the CUFen for environmental effects in the enhancement and what values to ensure that they do not AMP will be credited for the monitoring of environmental exceed the design limit (1.0).

effects (e.g., specific water chemistry parameters).

2. Explain the context of the phrase as The staff also requests clarification regarding the context of needed in the enhancement (e.g., if a the phrase, as needed in the enhancement (e.g., if a need need for the enhancement has not been for this enhancement has not been determined, why it has determined, why it has not been not been determined yet). determined yet).

The staff further requests clarification regarding why the 3. Discuss why the environmental effects environmental effects are not monitored for the EAF (e.g., water chemistry parameters such locations other than the sentinel locations even though as dissolved oxygen) are not monitored there is a need to ensure that the assumptions used in the

EAF analysis are valid for both sentinel and non-sentinel for the EAF locations other than the locations for the extended period of operation. sentinel locations even though there is a need to ensure that the assumptions for In addition, the staff requests clarification regarding whether environmental conditions used in the this enhancement include the monitoring of CUFen values to EAF analysis are valid for both sentinel ensure that the CUFen values do not exceed the design limit and non-sentinel locations. Alternatively, (1.0). discuss a potential need to revise the enhancement in order to include the monitoring of environmental effects for EAF locations other than the sentinel locations.

3 B.2.2.1 B-21 LRA Section B.2.2.1 addresses Enhancement 3 regarding 1. Clarify whether LRA Tables 4.3.1-2, the parameters monitored or inspected program element 4.3.1-3 and 4.3.1-4 include the thermal of the Fatigue Monitoring AMP. The enhancement states and pressure transients that will be that the program will be revised to account for additional added as part of Enhancement 3 of the critical thermal and pressure transients for components that Fatigue Monitoring AMP. If not, explain have been identified to have a fatigue time-limited aging why the transients to be added as part analysis (TLAA). of the enhancement are not evaluated in these LRA tables (e.g., evaluation to In comparison, LRA Section 4.3.1 addresses the design confirm that the 60-year projected transients and their 60-year cycle projections that are used cycles do not exceed the design in the fatigue TLAAs. Specifically, LRA Tables 4.3.1-2, transient cycles).

4.3.1-3 and 4.3.1-4 describe the reactor coolant system (RCS) transients, normal condition auxiliary system 2. Describe what transients will be added transients and auxiliary system transients with applicable as part of Enhancement 3 and the basis components, respectively. why these transients are not included in the existing fatigue monitoring.

The staff requests clarification regarding whether LRA Tables 4.3.1-2, 4.3.1-3 and 4.3.1-4 include the thermal and pressure transients that will be added as part of Enhancement 3 of the Fatigue Monitoring AMP. If not, the staff requests clarification regarding why the transients to be added in the enhancement are not evaluated in these tables in LRA Section 4.3.1.

In addition, the staff requests clarification regarding the identification of which transients will be added as part of the

enhancement and the basis why these transients are not included in the existing fatigue monitoring.

4 B.2.2.1 B-21 LRA Section B.2.2.1 addresses Enhancement 4 regarding 1. Clarify whether the acceptance criteria the acceptance criteria program element of the Fatigue related to transient cycles will be Monitoring AMP. The enhancement states that the program established in such as manner to will be modified to include acceptance criteria based on the ensure that the fatigue design limit is not 60-year cycle projections used in the supporting analyses. exceeded (e.g., CUF and CUFen do not exceed 1.0).

The staff noted that the enhancement does not clearly discuss whether the acceptance criteria for transient cycles 2. Clarify whether the acceptance criteria will be established in such a manner to ensure that the addressed in the enhancement include fatigue design limit is not exceeded (e.g., CUF and CUFen the criteria for parameters other than do not exceed 1.0). transient cycles. If so, clarify those parameters and their acceptance criteria The staff also requests clarification regarding whether the that will be addressed in the acceptance criteria addressed in the enhancement include enhancement.

the criteria for parameters other than transient cycles.

5 B.2.2.1 B-25 LRA Section B.2.2.1 addresses Enhancement 5 regarding 1. Explain the specific clarity that will be the corrective actions program element of the Fatigue provided regarding when to initiate Monitoring AMP. The enhancement states that the program corrective action in the will be modified to provide clarity on when to initiate enhancement. As part of the response, corrective action. describe whether the enhancement includes a timely initiation of corrective The staff noted that the enhancement does not clearly actions to address the CUF values that explain what clarity will be specifically provided regarding approach the screening criteria (0.1) for when to initiate corrective action. The staff also requests HELB location postulation.

clarification regarding whether this enhancement include a timely initiation of corrective actions to address the CUF 2. Clarify whether the corrective actions for values that approach the screening criteria (0.1) for high new additional HELB locations are also energy line break (HELB) location postulation described in part of the enhancement (e.g.,

LRA Section 4.3.5, High-Energy Line Break Analyses. additional HELB analysis for newly identified break locations and their In addition, the staff requests clarification regarding whether effects during the period of extended the corrective actions for new additional HELB locations are operation). If so, revise the also part of this enhancement. enhancement accordingly. If not, confirm that the existing program

includes such corrective actions for newly identified, additional HELB locations and the associated HELB analyses.

6 B.2.2.1 B-21 Regulatory Issue Summary (RIS) 2008-30, Fatigue 1. Provide the operating experience Analysis of Nuclear Power Plant Components, addresses evaluation regarding the potential fatigue usage calculations that consider components concern addressed in RIS 2008-30 to response to a step change in temperature. The fatigue confirm that the Fatigue Monitoring AMP analysis discussed in the RIS pertains to a detailed stress does not have such a concern.

analysis of the component with the use of the Greens (or influence) function.

The RIS indicates that the concern involves an input in which only one value of stress is used for the evaluation of the actual plant transients in the detailed stress analysis for the component. The RIS also discusses that the detailed stress analysis requires consideration of six stress components, as discussed in ASME Code,Section III, Subsection NB, Subarticle NB-3200.

In comparison, LRA Section B.2.2.1 evaluates the operating experience related to the Fatigue Monitoring AMP. However, the operating experience discussion in LRA Section B.2.2.1 does not include the evaluation regarding RIS 2008-30. The staff requests clarification regarding whether the Fatigue Monitoring AMP does not have the concern addressed in RIS 2008-30.

Comanche Peak Nuclear Power Plant, Units 1 and 2 License Renewal Application (LRA) Breakout Audit Questions LRA Section B.2.3.6 Thermal Aging Embrittlement of Cast Austenitic Stainless Steel LRA Background / Issue No. LRA Section Discussion Question / Request Page (As applicable/needed) 1 Section B-52 LRA section refers to an outdated NUREG/CR-4513. It also Is the program owner aware of B.2.3.6 states ferrite contents were calculated based on its guidance. NUREG/CR-4513, Revision 2 w/ Errata?

The staff notes that NUREG/CR-4513, Revision 2 w/ Errata was Discuss whether the proposed program is published in March of 2021. also consistent with the guidance of NUREG/CR-4513, Revision 2 w/Errata.

Flaw Tolerance Evaluation performed by Westinghouse, Flaw Tolerance Evaluation for Susceptible Reactor Coolant Loop Cast Austenitic Stainless Steel Piping Components in Comanche Peak Units 1 and 2 for 60-Year License Renewal, refers to and uses NUREG/CR-4513, Revision 2 w/ Errata.

2 Section B-52 Page17 of document LTA-SDA-20-087-NP, Revision 0, Flaw Discuss how acceptance criteria of B.2.3.6 Tolerance Evaluation for Susceptible Reactor Coolant Loop Cast different ferrite contents were reconciled.

Austenitic Stainless Steel Piping Components in Comanche Discuss if the assumed mode of failure is Peak Units 1 and 2 for 60-Year License Renewal, states the conservative in the flaw tolerance subject components (CF8A materials) contain less than 25% evaluation.

ferrite. The evaluation procedures used were based on Appendix C of ASME Section Xi,2007 edition with 2008 addenda which has a restriction of 20% ferrite content. In addition, two modes of failures were postulated - plastic collapse and unstable ductile tearing.

Comanche Peak Nuclear Power Plant, Units 1 and 2 License Renewal Application (LRA) Breakout Audit Questions LRA AMR Items Cracking Due to Stress Corrosion Cracking LRA No. LRA Section Question / Issue Why are we asking?

Page 1 Section 3 3.2-20 The applicant claimed that Generic Aging Lessons Learned According to 10 CFR 54.21 (GALL) Report item 3.2-1, 021 is not applicable because the and GALL Report, Table 3.2-1 Comanche Peak safety injection (SI) accumulators are accumulators exposed to Item 3.2-1, maintained at containment ambient conditions (<140 °F). treated water (borated) >140 021 However, the Updated Final Safety Analysis Report states that °F is within scope of license the accumulators are located inside containment, and are renewal and subject to aging operated at temperature between 70 °F to 150 °F. Clarify management review.

inconsistency between the license renewal application and GALL Report.

Comanche Peak Nuclear Power Plant, Units 1 and 2 License Renewal Application (LRA) Breakout Audit Questions LRA/SLRA TLAA Section 4.7.1 - Leak-Before-Break Question LRA/SLRA LRA/SLRA Background/Issue Discussion Question/Request Number Section Page 1 4.7.1 4.711 NUREG-0797, Supplement 23, Safety In NUREG-0797, Supplement 23, Safety Evaluation Report related to the operation of Evaluation Report related to the operation Comanche Peak Steam Electric Station, Units 1 of Comanche Peak Steam Electric Station, and 2 Units 1 and 2, the staff identified a concern related to potential thermal stratification in the pressurizer surge line during forced cooldown of the reactor coolant system (RCS) to effect repairs of leakage discovered in the surge line during normal plant operations. The staffs concern is that the combined thermal stresses associated with the forced cooldown process and the thermal stratification phenomenon could overstress the potentially weakened surge line implied by the presence of leakage in the line. In response to the staffs concerns, the applicant committed to revise the plant operating procedures to provide prompt depressurization in the event of a pressurizer surge line leak. Please provide verification that the plant operating procedures were revised and please provide any recent additional modifications to the plant procedures which address depressurization in the event of a pressurizer surge line leak.

2 4.7.1 4.7-1 NUREG-0797, Supplement 23, Safety In NUREG-0797, Supplement 23, Safety Evaluation Report related to the operation of Evaluation Report related to the operation Comanche Peak Steam Electric Station, Units 1 of Comanche Peak Steam Electric Station, and 2 Units 1 and 2, the applicant committed to monitor the temperature of the residual heat removal (RHR) suction lines for the potential for thermal fatigue. The applicant stated that, should thermal fatigue develop, the applicant would be alerted by fluctuating temperatures on the RHR lines. The staff concluded that the monitoring program will be adequate to confirm that the RHR suction lines will not fail as a result of thermal fatigue. The staff stated that the monitoring program is to be continued until sufficient data are developed, either through industry generic or plant-specific programs. In a letter dated August 9, 1989, the applicant agreed to obtain staff approval before terminating the monitoring program. Provide information whether the monitoring program is still being utilized, and if not, what other programs are being utilized to monitor the RHR suction lines for the potential for thermal fatigue.

3 4.7.1 4.7-1 Alloy 182/82 welds are susceptible to PWSCC. In the time limited aging analysis (TLAA), it states Comanche Peak, Unit 2 has completed the partial implementation of a mechanical stress improvement process (MSIP), where the loop 4 cold leg and loop 2 hot leg nozzles have achieved the required compressive residual stresses on the inner surface to mitigate primary water stress corrosion cracking (PWSCC) concerns for Alloy 82/182 welds. Please

provide a schedule for the completion of the MSIP for the remaining nozzle locations for Unit 2.

4 4.7.1 4.7-1 The applicant states that only a partial of the Please provide how the applicant is Alloy 182/82 welds have undergone a monitoring the unmitigated Alloy 82/182 mitigation. welds via an aging management program (AMP), inservice inspection (ISI),

walkdowns, etc.

5 4.7.1 4.7-2 The applicant states that DMW locations at the In the TLAA, the applicant states that RPV nozzles were evaluated for LBB. dissimilar metal welds (DMW) locations at reactor pressure vessel (RPV) nozzles that have Alloy 82/182 weld materials were evaluated for Leak-Before-Break (LBB). Please provide a list of the DMW locations.

6 4.7.1 4.7-2, 4.7-3 Clarification is needed for the dispositions Please clarify why the dispositions for the between the reactor coolant loop piping and the reactor coolant primary loop piping LBB accumulator injection, RHR and pressurizer analysis is 10 CFR 54.21(c)(1)(ii) and the surge lines. disposition for the accumulator injection lines, RHR lines and the pressurizer surge line piping is 10 CFR 54.21(c)(1)(i). The reviews which came to the conclusions both appear to be based on the projected 60-year cycles vs. the 40-year design cycles.

Comanche Peak Nuclear Power Plant, Units 1 and 2 License Renewal Application (LRA) Breakout Audit Questions LRA Section 4.3.6, High-Energy Line Break Analyses Question LRA LRA Background / Issue Discussion Question / Request Number Section Page (As applicable/needed) 1 4.3.6 4.3-22 LRA Section 4.3.6 addresses the high energy line break 1. Clarify whether the HELB location (HELB) analyses. The LRA section indicates that, in the postulation for ASME Code non-Class 4.3-23 HELB analyses, the time limited portion of the analysis is 1 piping, which involves SA, is one of related to the screening criterion of a CUF value 0.1 for the bases for identifying the HELB break location postulation. analysis as a TLAA. If not, explain why the HELB location postulation for In comparison, Final Safety analysis Report (FSAR), Section ASME Code non-Class 1 piping is not 3.6B.2 describes the current licensing basis (CLB) screening a basis for identifying the HELB criteria that are used to determine the intermediate locations analysis as a TLAA.

of postulated breaks for the HELB analyses. Specifically, FSAR Section 3.6B2.1.2 indicates that the CUF value of 0.1 2. Clarify whether additional break is included in the screening criteria for HELB location locations and their effects will be postulation for ASME Code Section III Class 1 piping. evaluated in the HELB analysis as part of corrective actions under the Fatigue FSAR Section 3.6.B2.1.2 also indicates that the postulation Monitoring aging management program of HELB locations for ASME Code non-Class 1 piping is, in if new additional piping break locations part, based on the allowable stress range for expansion are identified based on (1) the CUF stress (SA), consistent with Branch Technical Position MEB threshold of 0.1 or (2) the reduction in 3-1 (ADAMS Accession No. ML052340555). SA may need to SA. If not, explain why such additional be adjusted by a stress range reduction factor that is HELB locations do not need to be determined by the number of thermal cycles, as addressed evaluated in the HELB analysis.

in the implicit fatigue analysis in LRA Section 4.3.3.

However, LRA Section 4.3.6 does not clearly discuss whether the HELB location postulation for ASME Code non-Class 1 piping, which involves SA, is a basis for identifying the HELB analysis as a time-limited aging analysis (TLAA).

In addition, LRA Section 4.3.6 does not address what corrective action will be taken if additional break locations are identified due to the increased fatigue cycles for ASME Code Class 1 and non-Class 1 piping in the HELB analysis during the period of extended of operation.

Comanche Peak Nuclear Power Plant, Units 1 and 2 License Renewal Application (LRA) Breakout Audit Questions LRA Section 4.3.5, Reactor Vessel Internals Fatigue Analyses Question LRA LRA Background / Issue Discussion Question / Request Number Section Page (As applicable/needed) 1 4.3.5 4.3-21 LRA Section 4.3.5 addresses the fatigue time-limited aging 1. Clarify whether the bypass line analyses (TLAAs) for reactor vessel internal (RVI) tempering valve transient of Unit components. The applicant indicated that the following reference 2 in LRA Table 4.3.1-2 is identical for CPNPP stretch power uprate (SPU) includes the most recent to the split flow bypass valve fatigue evaluations in the current licensing basis (CLB) for RVI transient of Unit 2 in WCAP-components (

Reference:

WCAP-16840-NP, Comanche Peak 16840-NP, Table 2.2.6-1. If so, Nuclear Power Plant Stretch Power Uprate Licensing Report, explain why the design cycles for Rev. 0, ADAMS Accession Nos. ML072490310 and these transients are different (i.e.,

ML072490358). 20 cycles versus 40 cycles).

The applicant also explained that the fatigue evaluation in the 2. If the bypass line tempering reference determined that the SPU did not affect the bounding valve transient of Unit 2 in LRA cumulative usage factors (CUFs) for RVI components and, Table 4.3.1-2 is not identical to the therefore, the CUF values continue to meet the design limit (not split flow bypass valve transient to exceed 1.0). of Unit 2 in WCAP-16840-NP, explain why this inconsistency in In addition, the applicant indicated that the analyses performed the design transients are for the RVI components are based upon the subset of the reactor acceptable for the fatigue TLAAs coolant system design transients used in the fatigue analyses for on ASME Code Class 1 piping the reactor vessel, which are shown in LRA Table 4.3.1-2. In systems, non-Class 1 piping comparison, the design transients used in the CLB CUF systems and RVI components. As evaluations for RVI components are included in WCAP-16840-NP part of the response, clarify report, Table 2.2.6-1. whether these valve transients are In its review, the staff noted the potential inconsistency in the the transients that should be design transients between LRA Table 4.3.1-2 and WCAP-16840- included in the fatigue analyses for NP, Table 2.2.6-1. Specifically, LRA Table 4.3.1-2 include the RVI components.

bypass line tempering valve transient, which is only applicable

to CPNPP Unit 2 and has 20 design cycles. However, this transient is not included in WCAP-16840-NP, Table 2.2.6-1.

In addition, WCAP-16840-NP, Table 2.2.6-1 includes the split flow bypass valve transient, which is only applicable to CPNPP, Unit 2 and has 40 design transients. However, this transient is not included in LRA Table 4.3.1-2.

Therefore, the staff found a need to clarify the following items: (1) whether the bypass line tempering valve transient LRA Table 4.3.1-2 is identical to the split flow bypass valve transient in WCAP-16840-NP, Table 2.2.6-1 and, if so, why the design cycles for these transients are different (i.e., 20 cycles in LRA 4.3.1-2 and 40 cycles in WCAP-16840-NP, Table 2.2.6-1); and (2) if these transients are not identical, why the design transients in LRA Table 4.3.1-2 are not consistent with the existing design transients in WCAP-16840-NP.

2 4.3.5 4.3-21 LRA Section 4.3.5 addresses the fatigue time-limited aging 1. Clarify whether a time-limited analyses (TLAAs) for reactor vessel internal (RVI) components. assumption is involved in the fatigue evaluation for the RVI The applicant indicated that the following reference for CPNPP baffle former bolts that are related stretch power uprate includes the most recent fatigue evaluations to fatigue test results. If so, in the current licensing basis (CLB) for RVI components discuss the fatigue TLAA on the

(

Reference:

WCAP-16840-NP, Comanche Peak Nuclear Power baffle former bolts for the Plant Stretch Power Uprate Licensing Report, Rev. 0, ADAMS extended period of operation and Accession Nos. ML072490310 and ML072490358). its disposition in accordance with Note (2) of WCAP-16840-NP, Table 2.2.3-6 indicates that the 10 CFR 54.21(c)(1)(i), (ii) or (iii).

basis of the baffle-former bolt qualification is a fatigue test and the evaluation of the revised loads consisted of demonstrating that the loads associated with stretch power uprate are acceptable for the plant design life (i.e., 40 years).

However, LRA Section 4.3.6 does not clearly discuss whether the baffle former bolts are also qualified for the extended period of operation (up to 60 years of operation). Therefore, the staff found a need to clarify whether the applicant has adequately evaluated

the potential time-limited assumption in the fatigue evaluation for the baffle former bolts.

Comanche Peak Nuclear Power Plant, Units 1 and 2 License Renewal Application (LRA) Breakout Audit Questions LRA Section 4.3.4, Environmentally Assisted Fatigue Question SLRA SLRA Background / Issue Discussion Question / Request Number Section Page (As applicable/needed) 1 4.3.4 4.3-14 LRA Section 4.3.4 addresses the environmentally assisted 1. Clarify whether the more recent fatigue (EAF) analysis for ASME Code Section III Class 1 industry guidance for fatigue design piping and components. curves mentioned as part of the screening evaluation is consistent with LRA Section 4.3.4 indicates that, during the screening RG 1.207 that approves the use of evaluation of the EAF analysis, the applicant adjusted the NUREG/CR-6909, Revision 1 for EAF cumulative usage factor (CUF) values by any applicable analysis.

factors to correct for differences between the fatigue curves used in the existing fatigue evaluation (e.g.,Section III 2. Describe the adjustment factor that Appendix I of the ASME Code) and the fatigue curves was used to adjust the existing fatigue applicable to the industry document, as required for design curve in consideration of the environmental cumulative usage factor (CUFen) calculations more recent guidance on fatigue for license renewal. The existing fatigue analysis is also design curves for each material (i.e.,

called source fatigue analysis. each of carbon steel, low-alloy steel, stainless steel and nickel alloy). In The staff found a need to clarify whether the more recent addition, explain the technical bases of industry guidance for fatigue design curves is consistent with the adjustment factors for the fatigue RG 1.207 that approves the use of NUREG/CR-6909, design curves and CUFen Revision 1 for EAF analysis. calculations.

The staff also needs to confirm the adequacy of the adjustment factor used to adjust the existing fatigue design curve in consideration of the more recent guidance on fatigue design curves for each material (i.e., each of carbon steel, low-alloy steel, stainless steel and nickel alloy).

2 4.3.4 4.3-15 LRA Section 4.3.4 addresses the environmentally assisted 1. Explain how the applicant determined fatigue (EAF) analysis for ASME Code Section III Class 1 the maximum Fen values for the piping and components. materials in the EAF screening evaluation. As part of the discussion, LRA Section 4.3.4 indicates that in the EAF screening clarify whether the calculations of the evaluation the applicant used the maximum environmental maximum Fen values are consistent fatigue correction factor (Fen). However, the section does not with the guidance in NUREG/CR-6909, clearly describe how the applicant determined the maximum Revision 1.

Fen values.

3 4.3.4 4.3-15 LRA Section 4.3.4 addresses the environmentally assisted 1. Explain the stress analysis method fatigue (EAF) analysis for ASME Code Section III Class 1 rankings and their technical bases for 4.3-16 piping and components. the sentinel location identification.

LRA Section 4.3.4 indicates that, in the further evaluation of 2. Clarify whether EAF locations, which EAF for sentinel (limiting) location identification, the applicant were identified from the screening considered the technical rigor of different stress analysis evaluation, are removed from the methods and the level of conservatism associated with the sentinel location list only if both the stress analysis methods. The applicant explained that the screening CUFen value and stress results of determining the technical rigor and the associated analysis method ranking are lower than conservatism are the stress analysis method rankings for those of a more limiting location, EAF locations (also called stress basis comparison respectively. If not, provide justification rankings). for why the EAF locations with the higher screening CUFen or higher The applicant indicated that the lowest stress analysis stress analysis method ranking are method ranking involves the highest conservatism in the removed from the sentinel location calculations of screening environmental cumulative usage list.

factor (screening CUFen) values among the stress analysis methods. The applicant also explained that EFA locations with the lower screening CUFen values and lower rankings may be removed from the sentinel location list in comparison with the other EAF locations.

However, the applicant did not clearly discuss the stress analysis method rankings and their technical bases. In addition, the staff found a need to clarify whether EAF locations are removed from the sentinel location list only if both the screening CUFen value and stress analysis method

ranking are lower than those of a more limiting location, respectively.

4 4.3.4 4.3-16 LRA Section 4.3.4 addresses the environmentally assisted 1. Clarify the following items related to the fatigue (EAF) analysis for ASME Code Section III Class 1 sentinel location identification: (1) piping and components. which transient sections do not identify a sentinel location; (2) which transition LRA Section 4.3.4 indicates that, in the further evaluation of sections are bounding for the transition EAF for sentinel (limiting) location identification, the applicant sections that do not identify a sentinel compared sentinel locations of different transient sections location; and (3) how the applicant within common systems or equipment to determine one or determined that the other transition two sentinel locations per system or equipment. The sections and their sentinel locations are applicant defined a transient section as a group of sub- sufficiently bounding for the transition components and locations that experience the same sections that do not identify a sentinel transients (i.e., thermal, and related loadings). location and their maximum screening The staff found a need to clarify the following items related to CUFen.

the sentinel location identification: (1) which transient 2. In addition, explain how other transition sections do not identify a sentinel location; (2) which sections and their sentinel locations transition sections are bounding for the transition sections can be bounding for certain transition that do not identify a sentinel location; and (3) how the sections and their leading EAF applicant determined that the other transition sections are locations even though different sufficiently bounding for the transition sections that do not transition sections experience different identify a sentinel location given that different transition transients. As part of the discussion, sections experience different transients. clarify whether the fatigue monitoring activities provide reasonable assurance that the CUFen values of a transition section bounded by another transition section do not exceed the design limit (1.0).

5 4.3.4 4.3-17 LRA Section 4.3.4 addresses the environmentally assisted 1. Discuss in more detail the stress fatigue (EAF) analysis for ASME Code Section III Class 1 algorithm refinements and the more piping and components. LRA Section 4.3.4 describes the appropriate stress concentration EAF evaluation of the sentinel locations (limiting locations) factors, which were used to reduce the that were determined in the screening evaluation. conservatisms in the existing CUF calculations. As part of the responses, The applicant explained that, for some EAF locations, minor describe the Code provisions or conservatisms in the existing fatigue analysis were removed guidance documents used in the through approaches such as stress algorithm refinements refinements of CUF values for license and use of more appropriate stress concentration renewal.

factors. This group of EAF locations, which reduced minor conservatism, is also called the simplified evaluation group in the LRA section.

However, LRA Section 4.3.4 does not clearly describe the stress algorithm refinements and the more appropriate stress concentration factors, which were used to reduce the conservatisms in the existing CUF calculations.

6 4.3.4 4.3-19 LRA Section 4.3.4 addresses the environmentally assisted 1. Clarify whether the applicant will submit fatigue (EAF) analysis for ASME Code Section III Class 1 the 60-year projected CUFen values of 4.3-20 piping and components. LRA Tables 4.3.4-1 and 4.3.4-2 the plant-specific sentinel locations, describe the sentinel locations (limiting locations) for the which will be calculated as part of the Class 1 components and piping lines, respectively, based on Fatigue Monitoring AMP, for staffs EAF screening evaluation. review and approval a certain time period prior to entering the period of In addition to the screening evaluation results, these LRA extended operation (e.g., at least one tables provide the 60-year projected environmental year prior to entering the period of cumulative usage factor (CUFen) values for the generic extended operation). If so, revise the sentinel (limiting) locations described in NUREG/CR-6260, LRA accordingly. If not, provide which are applicable to the Comanche Peak Nuclear Power justification for why such a submittal is Plant. not necessary to confirm that the However, LRA Tables 4.3.4-1 and 4.3.4-2 do not provide 60- Fatigue Monitoring AMP and the year projected CUFen values for the plant-specific sentinel associated CUFen calculations will locations determined in the screening evaluation (e.g., effectively manage the aging effect of control rod drive mechanism housings and reactor vessel EAF for the plant-specific sentinel bottom mounted instrumentation tubes). These plant- locations without additional aging specific locations are additional sentinel locations that may management activities (e.g., flaw be more limiting than the generic sentinel locations tolerance evaluations).

described in NUREG/CR-6260. 2. Clarify how the Steam Generators AMP LRA Section 4.3.4 indicates that the detailed calculations of will manage the aging effect of EAF for CUFen values for these plant-specific sentinel locations will the steam generator components other be performed as part of the Fatigue Monitoring aging than steam generator tubes, which are management program (AMP). Specifically, LRA Tables listed in LRA 4.3.4-1. As part of the 4.3.4-1 and 4.3.4-2 explain that, for the plant-specific response, describe the aging sentinel locations associated with note (b) of the tables, the management activities (e.g., inspection CUFen values evaluation will be calculated as part of the activities) for the non-tube components Fatigue Monitoring AMP (LRA Section B.2.2.1). of steam generators and why these activities are sufficient for the aging However, LRA Section 4.3.4 does not clearly discuss management of the steam generator whether the applicant will submit the 60-year projected components other than tubes without CUFen values of the sentinel locations, which will be CUFen calculations.

calculated as part of the Fatigue Monitoring AMP, for staffs review and approval a certain time period prior to entering

the period of extended operation (e.g., at least one year prior to entering the period of extended operation).

The staff views that such a submittal for staffs review is necessary to confirm that the Fatigue Monitoring AMP and the associated CUFen calculations will effectively manage the aging effect of EAF for the plant-specific sentinel locations without additional aging management activities (e.g., flaw tolerance evaluations).

In addition, LRA Table 4.3.4-1 identifies plant-specific sentinel locations of steam generator components, which are associated with note (c) of the table (e.g., steam generator tubes, tube plate/lower shell location (Unit 1 only) and tubesheet primary side junction of lower shell channel head (Unit 2 only)). Note (c) of LRA Table 4.3.4-1 indicates that the applicant will use the Steam Generators AMP to manage the aging effect of EAF for these steam generator components.

The staff found a need to clarify how the Steam Generators AMP will manage the aging effect of EAF for the steam generator components other than steam generator tubes, which are listed in LRA 4.3.4-1.

7 4.3.4 4.3-20 LRA Table 4.3.4-2 describes the sentinel (limiting) locations 1. Explain why LRA Table 4.3.4-2 includes of EAF for piping lines and the associated 60-year projected sentinel locations of piping only CUFen values. The table identifies only stainless steel as a fabricated with stainless steel. If the fabrication material of piping lines and does not include applicant determined that the stainless carbon steel, low alloy steel or nickel alloy. steel piping locations bound the piping locations fabricated with low alloy steel, In comparison, LRA 4.3.4 indicates that the sentinel location carbon steel or nickel alloy in a is identified for each material type in a given transient transition section, provide the basis of section, which is a group of sub-components and locations the applicants determination on the that experience the same transients (thermal and related bounding nature of the stainless steel loadings). locations (e.g., comparisons of Fen and Therefore, the staff found a need to clarify why LRA Table CUFen values between the different 4.3.4-2 does not include a sentinel location of piping materials to determine the bounding fabricated with carbon steel, low alloy steel or nickel alloy. location and material).

Comanche Peak Nuclear Power Plant, Units 1 and 2 License Renewal Application (LRA) Breakout Audit Questions LRA Section 4.3.3, ASME Section III, Class 2 and 3 Allowable Stress Analyses Question LRA LRA Background / Issue Discussion Question / Request Number Section Page (As applicable/needed) 1 4.3.3 4.3-10 LRA Section 4.3.3 addresses the allowable stress analyses for 1. Provide the following information the non-Class 1 piping systems that were designed in related to the total cycle projections 4.3-8 accordance with the requirements of ASME Code,Section III for each piping system or line (Class 2 and 3) and ANSI B31.1 Code. described in LRA Table 4.3.2-4: (1) which specific design transients LRA Section 4.3.3 indicates that LRA Table 4.3.2-4 were considered in the total cycle demonstrates that the 60-year projected transient cycles for projections; (2) 60-year projected these piping systems do not exceed 7000 cycles specified in cycles of the specific design ASME Code,Section III and, therefore, a stress range transients; and (3) technical bases reduction factor of 1 (i.e., no reduction) is applied to the for how the projected cycles were allowable stresses in the stress analyses. determined (e.g., piping system However, LRA Table 4.3.2-4 does not clearly describe the design information, plant operation following items related to the total cycle projections for each procedures, test requirements, piping system or line: (1) which specific design transients were UFSAR information and specific considered in the total cycle projections; (2) 60-year projected system-level knowledge).

cycles of the specific transients; and (3) technical bases for how 2. Describe how the applicant the projected cycles were determined (e.g., piping system estimated the total 60-year projected design information, plant operation procedures, test transient cycles for the reactor requirements, UFSAR information and specific system-level coolant system of CPNPP Units 1 knowledge). and 2 (i.e., 3926 and 4081 cycles, LRA Section 4.3.3 also describes the total 60-year projected respectively). In addition, clarify transient cycles for the reactor coolant system of Comanche which piping systems and lines in Peak Nuclear Power Plant (CPNPP) Units 1 and 2 (i.e., 3926 LRA Table 4.3.2-4 are subject to and 4081 cycles, respectively). However the LRA does not these RCS transient cycles.

clearly describe how these total cycles were determined. In addition, the staff found a need to clarify which piping systems

and lines in LRA Table 4.3.2-4 are subject to these reactor coolant system (RCS) transient cycles.

Comanche Peak Nuclear Power Plant, Units 1 and 2 License Renewal Application (LRA) Breakout Audit Questions LRA Section 4.3.2, Metal Fatigue of Class 1 Components Question LRA LRA Background / Issue Discussion Question / Request Number Section Page (As applicable/needed) 1 4.3.2 4.3-9 LRA Section 4.3.2 addresses the fatigue time-limited aging 1. Discuss the specific code provisions analysis (TLAA) for ASME Code Section III, Class 1 piping that the applicant used in the fatigue and components. The section indicates that the reactor waiver evaluation and the reference coolant pumps conform to the waiver of fatigue requirements document that contains the fatigue of ASME Code,Section III and therefore do not require a wavier evaluation.

detailed fatigue evaluation.

However, the LRA does not describe specific code provisions that the applicant used in the fatigue waiver evaluation and the reference document that contains the fatigue wavier evaluation.

2 4.3.2 4.3-9 LRA Section 4.3.2 addresses the fatigue time-limited aging 1. Discuss the effect of the thread loss on analysis (TLAA) for ASME Code Section III, Class 1 piping the existing fatigue analysis of the most and components. limiting stud and hole (i.e., Unit 1 reactor vessel closure stud and hole During its review of operating experience related to fatigue number 25). As part of the discussion, analyses, the staff noted that the following reference clarify whether the 60-year projected indicates that some of the reactor vessel closure stud and cumulative usage factor (CUF) for the hole threads were damaged during the plant operation most limiting stud and hole is less than

(

Reference:

CR-2014-008181, Several Reactor Vessel the design limit (1.0). If not, discuss Closure Stud/hole Threads Have Incurred Damage Over the how the applicant will manage the Life of the Plant Resulting in Stud/hole Thread Loss, July effect of fatigue for the studs and holes 16, 2014). that may have a 60-year projected CUF Specifically, the reference indicates that the most limiting value exceeding the design limit.

thread loss occurred in the Unit 1 reactor vessel closure hole number 25. The reference also identifies a need to evaluate the fatigue life of the most limiting stud/hole if the fatigue life is affected.

However, LRA Section 4.3.2 does not discuss the effect of the thread loss on the existing fatigue analysis of the Unit 1 reactor vessel closure hole number 25 (limiting hole) and the associated stud.

Comanche Peak Nuclear Power Plant, Units 1 and 2 License Renewal Application (LRA) Breakout Audit Questions LRA Section 4.3.1, Transient Cycle Projections for 60 Years Question LRA LRA Background / Issue Discussion Question / Request Number Section Page (As applicable/needed) 1 4.3.1 4.3-8 LRA Section 4.3.1 addresses the design transients 1. Clarify whether LRA Table 4.3.1-4 describes and their 60-year cycle projections. Specifically, LRA the design transient cycles and their 60-year Table 4.3.1-4, describes the projected cycles related projected cycles for the auxiliary piping to the auxiliary piping systems (e.g., residual heat systems and the other ASME Code Section III removal and accumulator piping systems) connected non-Class 1 and ANSI B31.1 piping systems, to the reactor coolant system. which are not included in Class 1 piping systems. If not, provide justification for why In addition, the table addresses the transient cycles the table does not fully address the cycle for other ASME Code Section III non-Class 1 and projections for ASME Code Section III non-ANSI B31.1 piping systems (e.g., process sampling Class 1 and ANSI B31.1 piping systems other and liquid waste processing piping systems that are than the auxiliary piping systems.

not associated with the reactor coolant system or auxiliar piping lines connected to the reactor coolant 2. Clarify whether LRA Table 4.3.1-4 describes system). the non-Class 1 piping systems/lines and the total transient cycles for each of the non-However, the title of LRA Table 4.3.1-4, CPNPP 60- Class 1 piping systems/lines. As part of the year Projected Transient Cycles For Auxiliary System discussion, clarify the relationship between Transients and Applicable Components, does not LRA Tables 4.3.1-3 and 4.3.1-4.

clearly reflect that the table includes the transient cycle projections for ASME Code non-Class 1 and ANSI B31.1 piping systems other than the auxiliary piping systems.

Therefore, the staff found a need to clarify whether LRA Table 4.3.1-4 describes the design transients and their 60-year projected cycles for the auxiliary piping systems and the other ASME Code Section III non-

Class 1 and ANSI B31.1 piping systems, which are not included in the Class 1 piping systems.

In addition, it appears that LRA Table 4.3.1-4 mainly describes the non-Class 1 piping systems/lines and the total combined projected transient cycles for each of the non-Class 1 piping systems/lines (compared to a total of 7000 cycle limit). This aspect is not clearly discussed in LRA Section 4.3.1 and the first column of LRA Table 4.3.1-4 has a column description of Transient rather than Systems/Lines. The staff found a need to clarify this aspect of LRA Table 4.3.1-4.

2 4.3.1 4.3-7 LRA Section 4.3.1 addresses the design transients 1. Clarify whether LRA Table 4.3.1-3 includes and their 60-year cycle projections. Specifically, the the design transients of the upset and test title of LRA Table 4.3.1-3, CPNPP 60-year Transients conditions and their 60-year cycle Normal Condition Auxiliary System Transient Events, projections. If not, explain why the table does indicates that the table describes the normal condition not address the design transients of the upset transients and their 60-year cycle projections. and test conditions and their 60-year cycle projections.

Accordingly, the title of LRA Table 4.3.1-3 suggests that the table does not address the 60-year transient 2. Clarify whether LRA Table 4.3.1-3 includes cycles projections for the transients of the upset or the design transients for the ASME Code test conditions. Section III non-Class 1 piping and ANSI B31.1 piping other than the auxiliary piping Therefore, the staff found a need to clarify whether connected to the reactor coolant system (e.g.,

LRA Table 4.3.1-3 includes the design transients of the process sampling related transient). If not, upset and test conditions and their 60-year cycle explain why the table does not address the projections. design transients for the non-Class 1 piping In addition, the staff need to clarify whether LRA Table and ANSI B31.1 piping other than the 4.3.1-3 includes the design transients for the ASME auxiliary piping connected to the reactor Code Section III non-Class 1 piping and ANSI B31.1 coolant system.

piping other than the auxiliary piping connected to the reactor coolant system (e.g., process sampling related transient).

3 4.3.1 4.3-7 LRA Section 4.3.1 addresses the design transients 1. Explain why the 60-year projected cycles are and their 60-year cycle projections. Specifically, LRA inconsistent between the LTR-SDA-II-21-32-P Table 4.3.1-3 addresses the design transients and report and LRA Table 4.3.1-3 for the following their cycle projections for non-Class 1 piping systems. transients: 1) charging flow step decrease and return to normal transient; (2) charging The staff also noted that the following reference flow step increase and return to normal describes the 60-year projected cycles for non-Class 1 transient; (3) letdown flow step decrease and piping systems (

Reference:

LTR-SDA-II-21-32-P, return to normal transient; and (4) letdown Comanche Peak Unit 1 and 2 License Renewal: Class flow step increase and return to normal 2 and 3 Piping Fatigue Evaluation). transient. As part of the discussion, clarify The staff further noted that, for the following whether LRA Table 4.3.1-3 provides the transients, the 60-year projected cycles are adequate projected cycles for these inconsistent between the reference above and LRA transients.

Table 4.3.1-3: (1) charging flow step decrease and 2. For the charging/letdown cooldown and return to normal transient; (2) charging flow step charging/letdown heatup transients, increase and return to normal transient; (3) letdown describe (a) the technical basis for identifying flow step decrease and return to normal transient; these transients as design transients for non-and (4) letdown flow step increase and return to Class 1 piping systems in LRA Table 4.3.1-3 normal transient. and (b) which system/line transients in LRA For example, LRA Table 4.3.1-3 estimates a 60-year Table 4.3.1-4 include these charging/letdown projected cycle number of 4373 for the charging flow design transients.

step decrease and return to normal transient, which is significantly higher than that estimated in the LTR-SDA-II-21-32-P report.

In addition, the LTR-SDA-II-21-32-P report does not identify charging/letdown cooldown and charging/letdown heatup transients as design transients in contrast with LRA Table 4.3.1-3 that identifies those transients as design transient and describes their 60-year projected cycles.

The staff found a need to resolve the potential inconsistencies discussed above regarding the projected cycles numbers and the list of design transients for non-Class 1 piping systems.

4 4.3.1 4.3-7 LRA Section 4.3.1 addresses the design transients 1. For each piping system or line listed in LRA and their 60-year cycle projections. Specifically, LRA Table 4.3.1-4, clarify which specific design 4.3-8 Table 4.3.1-2 and 4.3.1-3 describe the design transients and their 60-year projected cycles, transients and their cycle projections for the reactor including the design transients and projected coolant system and non-class 1 piping systems, cycles in LRA Table 4.3.1-3, are considered in respectively. the determination of the total projected cycles for the piping system or line.

In addition, LRA Table 4.3.1-4 addresses the piping system or line transients and their 60-year projected 2. Describe which design transients in LRA cycles for the non-Class 1 piping. The projected cycle Section 4.3.1, including LRA Tables 4.3.1-2, number of a piping system/line transient may be 4.3.1-3 and 4.3.1-4, are not counted in the determined by combining the cycles of specific design Fatigue Monitoring AMP and the basis for the transients that are applicable to the piping system or absence of cycle counting (e.g., the design line. cycle number has a significant cycle margin compared to the 60-year projected cycles or However, LRA Table 4.3.1-4 does not clearly describe the transient does not cause an effect on which specific design transients and their projected fatigue).

cycles, including the design transients and cycles in LRA Tables 4.3.1-2 and 4.3.1-3, are considered in the determination of the total combined projected cycles for each piping system or line.

In addition, LRA Section 4.3.1 indicates that cycle counting is not performed on some design transients in the Fatigue Monitoring aging management program (AMP). However, LRA Section 4.3.1, including LRA Tables 4.3.1-2, 4.3.1-3 and 4.3.1-4, does not clearly describe which design transients are not counted in the Fatigue Monitoring AMP and the basis for the absence of cycle counting (e.g., the design cycle number has a significant cycle margin compared to the 60-year projected cycles or the transient causes a negligible effect on fatigue).

5 4.3.1 4.3-6 LRA Table 4.3.1-2 indicates that the 60-year projected 1. Describe the basis for the approach used in cycles for the following test transients are determined note (d) of LRA Table 4.3.1-2 (i.e., the design as the same with the current licensing basis design cycles of the test transients can be used as cycles: (1) primary side hydrotest transient; (2) the 60-year projected cycles without secondary side hydrotest transient; (3) primary side adjustment). As part of the response, clarify leak test transient; (4) secondary side leak test whether the actual cycles of these test transient; and (5) boron injection tank (BIT) check transients are significantly less than the 60-valve test transient (applicable only to Unit 2). Note year projected cycles.

(d) of LRA Table 4.3.1-2 also indicates that the design cycles of these test condition transients are used as the 60- year projected cycles without adjustment.

However, the staff found a need to further clarify the basis for the approach used in note (d) of LRA Table 4.3.1-2. Specifically, the staff found a need to clarify whether the actual cycles of these test transients are significantly less than the 60-year projected cycles.

6 4.3.1 4.3-3 LRA Section 4.3.1 addresses the design transients 1. Clarify why the Unit 1 letdown flow shutoff and their 60-year cycle projections. The LRA section with prompt return to service transient, which explains that the 40-year design transients bound the is identified as a design transient for non-number of cycles projected to occur during 60 years of Class 1 piping systems in LRA Table 4.3.1-3, operation except for Unit 1 letdown flow shutoff with and its cycles are used as input to the EAF prompt return to service transient. LRA Table 4.3.1-3 analysis that mainly addresses the describes a 60-year projected cycle number of 233, environmental effect on the metal fatigue in which is greater than a design cycle number of 200 for Class 1 piping systems and components.

the transient.

2. Considering that the number of 60-year LRA Section 4.3.1 also explains that the Unit 1 projected cycles for the Unit 1 letdown flow letdown flow shutoff with prompt return to service shutoff with prompt return to service transient transient was evaluated in the environmentally is greater than the number of design cycles assisted fatigue (EAF) analysis related to the limiting for the transient, clarify the following: (1)

(sentinel) locations defined in NUREG/CR-6260. whether the Unit 1 charging nozzle is the most limiting EAF location among the Unit 1 The staff noted that the EAF analysis in LRA Section piping, component and support locations that 4.3.4 and Table 4.3.4-2 indicate that the charging are subject to the transient; and (2) whether nozzle is the limiting EAF location for the Unit 1 the 60-year projected cumulative usage factor charging system and that the 60-year projected

environmental cumulative usage factor (CUFen) for the (CUF) values of the Unit 1 piping, component location is less than the design limit (1.0). and support locations (e.g., pressurizer support) subject to the transient do not However, it is not clear to the staff why the Unit 1 exceed the design limit (1.0).

letdown flow shutoff with prompt return to service transient, which is identified as a design transient for 3. In addition, clarify whether the cycles of the non-Class 1 piping systems in LRA Table 4.3.1-3, and Unit 1 letdown flow shutoff with prompt return its cycles are used as input to the EAF analysis that to service transient will be monitored to mainly addresses the environmental effect on the ensure that the CUF and CUFen values metal fatigue in Class 1 piping systems (i.e., reactor associated with this transient do not exceed coolant pressure boundary piping and components). the design limit (1.0) for the period of extended operation.

In addition, the staff found a need to clarify the following: (1) whether the Unit 1 charging nozzle is the most limiting EAF location among the Unit 1 piping and component locations that are subject to the Unit 1 letdown flow shutoff with prompt return to service transient; and (2) whether the 60-year projected cumulative usage factor (CUF) values of the Unit 1 piping, component and support locations subject to the Unit 1 letdown flow shutoff with prompt return to service transient do not exceed the design limit.

7 4.3.1 4.3-5 LRA Table 4.3.1-2 include design transients related to 1. As baseline information on operating plant loading and unloading (e.g., plant loading conditions related to fatigue analyses, discuss between 0 and 15 percent of full power and plant the following items: (1) whether CPNPP, Units unloading between 0 and 15 percent of full power 1 and 2 have been always operated a base transients). load unit and (2) whether the applicant has a plan to operate its reactor units as a load-following unit.

Comanche Peak Nuclear Power Plant, Units 1 and 2 License Renewal Application (LRA) Breakout Audit Questions LRA Cracking of Nickel-Alloy Components and Loss of Material Due to Boric Acid-Induced Corrosion in Reactor Coolant Pressure Boundary Components Question LRA/SLRA LRA/SLRA Background / Issue Discussion Question / Request Number Section Page (As applicable/needed) 1 XI.M11B 9-12, The requirements to impose N-729, N-722, and N-770 as Confirm AMP cites the regulations under 4.3.2 - 4.5.2, cited in the Aging Management Program (AMP) are under 10 CFR50.55a(g)(6)(ii)(D), (E) and (F) 4.10.2, 15-17, 10 CFR 50.55a(g)(6)(ii)(D), (E), and (F) and its conditions, with the required conditions at each time Appendix B 30-33 respectively. the applicant cites N-729, N-722, and N-770 in the current version of the AMP.

2 XI.M11B 10 of 28 Regulatory Issue Summary (RIS) 2018-06 was issued on Confirm the review of operating December 10, 2018, which clarifies the inspection experience for RIS 2018-06.

4.10 requirements for reactor pressure vessel upper head bare metal visual examinations 3 XI.M11B 10 of 28 Materials Reliability Program (MRP) 384, Guideline for Confirm the review of operating 4.10 Nondestructive Examination of Reactor Vessel Upper Head experience for MRP-384.

Penetrations, provides nuclear power plant owners with guidance for planning and executing reactor vessel upper head (RVUH) penetration examinations in a manner that will minimize the likelihood of human errors and maximize the probability of success. MRP-384 stated the following items under Table 7.1:

4 XI.M11B 8 of 28 In the St. Lucie Extended Period of Operation (EPO) Confirm that a TLAA is not necessary for request, the applicant identified full structural dissimilar your full structural overlayed dissimilar 4.4.2 metal butt welds required to be inspected under 10 CFR metal butt welds.

50.55a(g)(6)(ii)(F), which required a time limiting aging analysis (TLAA 4-7-8) due to potentially triggering additional inspections in accordance with Note 10 of Table 1 of N-770-5, Those welds not included in the 25% sample shall be

examined prior to the end of the mitigation evaluation period if the plant is to be operated beyond that time.

5 XI.M11B 8 of 28 The licensee identified a Mechanical Stress improvement Confirm that a TLAA is not necessary to 4.2.2 Process (MSIP') equipment failure which caused a the address this MSIP issue.

MSIP' for the Unit 2 nozzle hot and cold leg dissimilar metal welds only being partially completed in 2RF19.

6 XI.M11B 8 of 28 In response to item 4 above, the applicant noted that LRA Given the inservice inspection area of 4.4.2 Table 3.1.2-3 includes a line item for cumulative fatigue the SWOL is limited to the outer 25% of damage of the Pressurizer DMW (SWOL) which credits the susceptible material of the original TLAA discussed in LRA Section 4.3. Further the applicant weld, and the original weld remains notes that the LBB calculational methodology is applicable susceptible to PWSCC initiation and for the CPNPP and has been utilized for the LBB analysis growth, is the applicants AMP, and for Alloy 82/182 welds with SWOL for the pressurizer surge current methodology to address the line nozzle. Most significantly, the applicant explains that inspection frequency requirement of Note the acceptance criterion for the pressurizer SWOL is to 10 of ASME Code Case N-770-5, verify that an unidentified crack will not propagate to the adequate for the period of extended SWOL interface during a 10-year ISI interval. Since the operation?

crack is not qualified for the life of the plant, but only the inspection interval, the fatigue crack growth analysis is not a TLAA. Therefore, a TLAA pursuant to N-770-5 Note 10 is not applicable for CPNPP.

The NRC staff have reviewed the licensees response and discussion during the 3/16 breakout session. Under Section 4.0 Results, of LTR-SDA-11-20-19, a similar discussion to the position above is provided as the applicants review of a need for the TLAA for SWOL welds. However, this review is limited only to the fatigue growth mechanism.

As noted in Table 3-2 of LTR-SDA-11-20-19, Flaw growth due to stress corrosion cracking also potentially applies to CPNPP. Note 10 of Table 1 of N-770-5 establishes an inspection requirement as an augmented examination after the application of the SWOL at CPNPP. This requirement is

based on a calculation to determine the mitigation evaluation period to determine if the plant is to be operated beyond that time. This calculation includes the degradation mechanism of primary water stress corrosion cracking (PWSCC). Additionally in Section 5.0, Conclusion of the NRC safety evaluation authorizing the applicants request for the installation of the SWOL authorized the proposed modifications for the remaining service life of the subject welds. (ADAMS Accession No. ML072270704).

Comanche Peak Nuclear Power Plant, Units 1 and 2 License Renewal Application (LRA) Breakout Audit Questions One -Time Inspection of ASME Code Class 1 Small-Bore Piping Management Program (AMP)

Question LRA LRA Background / Issue Discussion Question / Request Number Section Pages 1 B.2.3.31 B-137 & LRA states that CPNPP 1 and 2 have not experienced a failure in Staffs understanding is that the its ASME Code Class 1 Piping in 32 and 29 years of statements in the LRA and the program B-139 operation. Therefore, the one-time program will inspect a sample basis document are applicable to all of a minimum of 3% of the weld population or a maximum of 10 ASME Code Class 1 piping at CPNPP 1 welds for each type for each unit. and 2, and not just the ASME Class 1 small-bore piping.

LRA further states, Review of plant-specific OE indicates that cracking of ASME Code Class 1 piping has not occurred at Please confirm if the above is applicable CPNPP. A similar statement is made in the program basis to all ASME Code Class 1 piping.

document LUM00020-REPT-058.

Additionally, staffs review of plant-specific OE confirmed that there do not appear to be any instances when cracking was identified on ASME Code Class 1 piping for either of the CPNPP 1 and 2.

2 NRC issued Information Notice (IN) 2007-21, Supplement 1 If this IN has not been reviewed for (ADAMS Accession ML20225A204), "Pipe Wear due to applicability to CPNPP, confirm when and Interaction of Flow-Induced Vibration and Reflective Metal what actions the applicant is planning to Insulation," to alert licensees to recent industry operating take to ensure this aging effect will be experience regarding potential abrasive wear of ASME Code managed.

Class 1 and 2 pipes caused by flow-induced vibration and reflective metal insulation conditions.

It appears that at least one of the instances of pipe wear from IN 2007-21, Supplement 1 was captured in Signed 1RF21 EOC21 Report. Specifically, external OE-466059 (page 7) discussed degraded reactor coolant system piping due to mirror insulation fretting and relayed the information to be shared by the sites

insulators that handle removal of insulation for flow accelerated corrosion-related inspections.

Comanche Peak Nuclear Power Plant, Units 1 and 2 License Renewal Application (LRA) Breakout Audit Questions LRA Section AMP B.2.3.27: Buried and Underground Piping and Tanks Question LRA LRA Background / Issue Discussion Question / Request Number Section Page (As applicable/needed) 1 B.2.3.27 B-158 LRA Section B.2.3.27, Buried and Underground Piping GALL Report Table XI.M412, Inspection of and Tanks, states [p]eriodic inspections will also be Buried and Underground Piping and Tanks, also performed based on plant OE [operating experience] and considers coatings, backfill, and soil corrosivity the performance of the plant cathodic protection system. when determining the number of periodic inspections. It is unclear to the staff if these factors will also be considered (in addition to OE and cathodic protection system performance).

2 B.2.3.27 B-158 LRA Section B.2.3.27 states [f]or steel components, the The staff requests a discussion with respect to acceptance criteria for the effectiveness of the cathodic cathodic protection acceptance criteria. GALL protection is less than or equal to -850 mV. A similar Report AMP XI.M41 recommends -850 mV statement is also included in the FSAR supplement. instantoff. The staff does not agree with the use of a potential of -850 mV instant-on without The staff reviewed MSE-P0-1328, Cathodic Protection measurement or calculation of voltage drops. In Annual Survey, and noted coppercopper sulfate addition, the staff disagrees with the use of the reference electrode voltage should be less than or equal 100 mV cathodic polarization acceptance to -0.85 volts instant off (for 1E piping) or -0.85 volts on ( criterion (in the mixed metal environment) for non-1E piping). without confirmatory testing to verify that all The staff reviewed EPG-9.03, Underground Pipe and metals are adequately protected.

Tank Program, and noted the cathodic protection systems acceptance criteria is -850 mV instant-off or the 100 mV shift.

3 N/A N/A GALL Report AMP XI.M41 recommends a cathodic The staff requests a discussion with respect to protection critical potential of 1,200 mV to prevent cathodic protection critical potentials. The staff damage to coatings or base metals. could not identify this recommendation in MSE-

P0-1328, Cathodic Protection Annual Survey, or in any of the enhancements.

4 B.2.3.27 B-159 Exception No. 1 states the following (in part): The staff requests a discussion on the exception with a focus on the following areas:

  • The DGFOSTs [diesel generator fuel oil storage tanks] are inspected internally every 20 years
  • Type(s) of external coatings used for the through visual inspection and ultrasonic thickness tanks.

measurements. The current wall thickness is evaluated for acceptability of the expected wall

  • Results of soil corrosivity testing thickness at the next scheduled inspection based conducted in 2010.

upon historical corrosion rates.

  • Whether the proposed inspection
  • The exteriors of the tanks are coated. frequency would be dependent on the future performance of the cathodic
  • Recent cathodic protection performance (within protection system.

the 10-yr period prior to the PEO) was reviewed based on pipe to soil potentials taken during

  • UT inspection results.

annual surveys, which indicates the FOSTs are being satisfactorily protected by the system.

  • Soil corrosivity samples around the site were taken in 2010. The soil sample analysis indicated the corrosion potential of buried systems was mitigated to minimal levels by sufficient cathodic protection.
  • Prior to being placed in service, each EDG fuel oil storage tank was inspected, and UT readings were taken. The UT readings were taken using a 42-point gridded inspection plan. Re-inspections, on a 10-year interval after being place in service, found the tanks with satisfactory results.

5 B.2.3.27 B-164 OE Example No. 2 states the following (in part): In April The staff requests a discussion with respect to if of 2015, an opportunistic inspection was performed during other inspections of inscope buried piping have the excavation process for a potable water leak which noted external coating damage (or if this is an exposed Fire Protection piping. The inspection noted isolated issue).

coating (coal tar wrap) damage. The inspection noted

construction dunnage still in place under the pipe, which is not in compliance with the requirements of 2323-SS-008, CPSES Excavation and Backfill Specification.

6 B.2.3.27 B-164 OE Example No. 3 states the following (in part): The The staff requests a discussion with respect to 2018 and 2019 health reports identified some issues with (a) if the leaks were due to age-related potable water leaks. degradation; and (b) if piping materials used in the potable water system are representative of in-scope buried piping.

7 B.2.3.27 B-160 LRA Section B.2.3.27 includes the following The staff requests a discussion with respect to enhancements related to monitoring fire pump activity. which fire pumps the enhancements are B-161 referring to. GALL Report AMP XI.M41

  • Revise procedures to trend the fire pump activity recommends monitoring jockey pump activity.

(or similar parameter) to identify concerns with buried fire water yard loop header leakage.

  • Revise acceptance criteria to ensure there is no evidence that backfill caused damage to the respective component coatings or the surface of the component (if not coated), and changes in fire pump activity (or similar parameter) that cannot be attributed to causes other than leakage from buried piping are not occurring.
  • Revise procedure to state when using the option of monitoring the activity of a fire pump instead of inspecting buried fire water system piping, a flow test or system leak rate test is conducted by the end of the next refueling outage or as directed by the current licensing basis, whichever is shorter, when unexplained changes in fire pump activity (or equivalent equipment or parameter) are observed.

LRA Section 2.3.3.7, Fire Protection System, states

[w]ater is supplied to the underground fire loop by the lead pump, the electric motor-driven pump, when the

jockey pump cannot maintain the system pressure above a predetermined set point.

8 N/A N/A The staff reviewed CR-2015-010120 and noted the piping Based on its review of the subject OE, the staff vault for the B train station service water system was requests a discussion with respect to if there is inspected and the general condition of the area consisted inscope underground piping at Comanche of a confined space with approximately 0.5 to 0.75 inches Peak.

of water on the floor.

Comanche Peak Nuclear Power Plant - NRC Integrated Inspection Report 5000445/2015004 and 05000446/2015004 (ML16035A494) notes [o]n October 17, 2015, the licensee identified corrosion on unit 2 service water piping, in an infrequently entered tunnel...

The GALL Report states [u]nderground piping and tanks are below grade, but are contained within a tunnel or vault such that they are in contact with air and are located where access for inspection is restricted.

Based on the staffs review of the LRA, there are no in-scope components exposed to an underground environment.

9 N/A N/A The staff reviewed CR-2020-006151 and noted based on The staff requests a discussion with respect to biocide results the leak was determined to be fire the cause of the subject leak.

protection water.

Comanche Peak Nuclear Power Plant, Units 1 and 2 License Renewal Application (LRA) Breakout Audit Questions LRA/SLRA Section /TLAA/AMP/Scoping and Screening:

Question LRA/SLRA Section LRA/SLRA Background / Issue Discussion Question / Request Number Page (As applicable/needed)

  1. 1 Item Number 3.2-1, 514/2289 Chapter XI.M29, Aboveground Metallic Tanks is not During my review of AMP XI.M36, the 067 (Comanche applicable because there are no stainless steel or AMP does not mention the use (and Peak Nuclear Power aluminum tanks (within the scope of Chapter XI.M29, inspection) of sealant or caulking at the Plant Aboveground Metallic Tanks) exposed to soil or interface between the tank external concrete in the Engineered Safety Feature (ESF) surface and concrete or earthen surface Units 1 and 2 Systems. to mitigate corrosion of the tank by License Renewal minimizing the amount of water and Application) However, the aboveground outdoor tanks in the ESF moisture penetrating the interface as Systems include the missile-protected, stainless steel- required by NUREG-2191 AMP From Item 3.2-1, lined concrete Refueling Water Storage Tank (RWST) in 004, (Comanche XI.M29. (Page 267/505) (GALL-SLR 488/2289 the CSS (Core Spray System.) The RWST lining Report, Vol. 2)

Peak Nuclear Power exposed to air -outdoor (above water line through vents Plant in the concrete tank) and concrete is included in items Are you planning to enhance the AMP Units 1 and 2 3.2-1, 004, and 3.2-1, 063. Chapter XI.M36, "External Surfaces License Renewal Monitoring of Mechanical Components."

The component Stainless steel Piping, piping to meet the minimal requirements of Application) components, and piping elements; tanks exposed to Air NUREG-1801 AMP Chapter XI.M29 From Item 3.2-1, - outdoor uses AMP XI.M36, "External Surfaces Aboveground Metallic Tanks? Please 063 Monitoring of Mechanical Components." submit updated drawings of the The Stainless-steel Piping, piping components, and Refueling Water Storage Tank (RWST)

(Comanche Peak piping elements exposed to Air - indoor, uncontrolled in the CSS (Core Spray System)?

Nuclear Power Plant (External), Air with borated water leakage, Concrete, Units 1 and 2 Gas, Air - indoor, uncontrolled (Internal.) Includes the License Renewal 512/2289 RWST liner that is encased in the concrete of the tank.

Application) Does not mention any AMP.

Comanche Peak Nuclear Power Plant, Units 1 and 2 License Renewal Application (LRA) Breakout Audit Questions LRA Section: B.2.3.15 Question LRA LRA Background / Issue Discussion Question / Request Number Section Page (As applicable/needed) 1 2.3.3.9 2.3-107 LRA Section 2.3.3.9, Potable and Sanitary Water System, Please discuss what material the Chlorination states, the CLS process tubing that enters the SWIS is System process tubing is and whether it could encased in either PVC or metallic piping. This section also leak prior to rupture, resulting in the PVC states, the PVC piping prevents the process tubing from piping and metallic penetration sleeve being leakage or spraying onto nuclear safety related components, exposed to sodium hypochlorite or sodium and The metallic piping encasing the process tubing is a bromide.

penetration sleeve which acts as a fire barrier.

LRA Table 3.5.2-15 includes carbon steel and stainless steel penetration sleeves with a fire barrier intended function. The identified environments are indoor uncontrolled air, outdoor air, and air with borated water leakage.

LRA Table 3.3.2-9a includes external and internal indoor uncontrolled air for the PVC piping. The staff notes that plant-specific note 1 states that during normal operation the process tubing is not expected to be ruptured, and therefore the PVC piping is exposed to an internal air - indoor (uncontrolled) environment.

It is unclear from the LRA what material the process tubing is and whether it may leak prior to rupture. If it may leak prior to rupture, then the PVC piping and metallic penetration sleeve could be exposed to sodium hypochlorite or sodium bromide.

2 2.4 2.4-47 LRA Section 2.4.15 and Table 2.4-15 includes carbon steel Please discuss whether the intent was to commodity fire protection hose stations (racks, reels, and manage the carbon steel commodity fire supports) managed by the Fire Protection program. protection hose stations (racks, reels, and However, the intended function for this commodity is supports) with the Fire Protection

Structural Support. It appears that this commodity was program. If so, please discuss how the Fire included in the Fire Barrier Commodity Group based on the Protection program will manage loss of statement in LRA Section 2.4.15 that states, That is, serve as material of the carbon steel fire protection a rated fire barrier or provide structural support for hose stations (rack, reel, and support) to components used for manual firefighting. ensure the Structural Support intended function will be maintained.

AMR Item 3.3-1, 059 in Table 3.3-1 is cited for managing fire protection hose stations (racks, reels, and supports) by the Please also discuss whether any of the Fire Protection program. This AMR item is cited in LRA Table carbon steel piping items in LRA Table 3.3.2-7 3.5.2-15. are associated with hose stations.

LRA Sections A.2.2.15 and B.2.3.15 do not address fire protection hose stations (rack, reel, and support). In addition, LUM00020-REPT-052 does not address this commodity.

LRA Section 2.3.3.7 and Table 2.3.3-7 include hose station with a Structural Support intended function. LRA Table 3.3.2-7 cites AMR Item 3.3-1, 078 to manage loss of material of carbon steel hose stations exposed externally to indoor uncontrolled air by the External Surfaces Monitoring of Mechanical Components program.

Section 4.1.2 of LUM00020-REPT-053 states, Fire hose stations and stand pipes are considered piping and are managed under this program [Fire Water System program].

There are several carbon steel piping items in LRA Table 3.3.2-7 that could be associated with hose stations, but it is unclear.

Section 8.6 of Procedure FIR-309 addresses hose station racks.

3 3.5 3.5-185 LRA Table 3.5.2-15 includes masonry block commodity Please discuss whether both the Masonry concrete block (removable) for opening with a fire barrier Walls and Fire Protection programs will intended function managed by the Masonry Walls and manage the masonry block commodity Structures Monitoring programs. The Fire Protection program concrete block (removable) for opening.

is not credited for managing applicable aging effects for this masonry block commodity. If the intent is for only the Masonry Walls program to manage this masonry block

Plant-specific note 1 in LRA Table 3.5.2-15 for this masonry commodity, then discuss how the program block commodity states, Furthermore, the Masonry Walls descriptions and procedures for the Masonry (B.2.3.33) AMP and Fire Protection (B.2.3.15) AMP credit and Walls and Fire Protection programs reflect communicate with each other. A similar statement is made in this.

LRA Table 3.5-1 for AMR item 3.5-1, 070. LRA Section B.2.3.33 states, Masonry walls that perform a fire barrier Finally, discuss whether plant-specific Note 3 intended function are also managed by the Fire Protection was supposed to cite the Structures (B.2.3.15) AMP. The removable concrete block openings are Monitoring program rather than the Masonry in a fire wall. Therefore, it appears that both the Masonry Walls program.

Walls and Fire Protection programs should be credited. The staff notes that LRA Section B.2.3.15 does not cite the Masonry Walls program. In addition, the staff did not identify where the Masonry Walls program was cited in LUM00020-REPT-052 as a program that credits or is credited by the Fire Protection program. FIR-311 which includes visual inspection of walls, floors, and ceilings does not reference the Masonry Walls or Structures Monitoring programs.

LUM00020-REPT-052 states that the Masonry Walls program is credited by the Fire Protection program. Section 4.4.2 of this document states, Masonry walls that are fire barriers are visually inspected in accordance with the CPNPP Fire Protection AMP [Ref. 9.16].

LUM00020-REPT-071 states that the Structures Monitoring program credits and is credited by the Fire Protection program.

Plant-specific note 3 in LRA Table 3.5.2-15 for this masonry block commodity states, The Masonry Walls (B.2.3.33) AMP and Fire Protection (B.2.3.15) AMP credit and communicate with each other. However, the Structures Monitoring program is credited for this line item.

4 3.5 3.5-185 LRA Table 3.5.2-15 includes galvanized steel commodity Please discuss why the Fire Protection damper housing. AMR Items 3.5-1, 095 (None) and 089 program is not cited for managing aging (Boric Acid Corrosion Program) are cited for this commodity. effects for the fire damper housing and why The Fire Protection program is not cited for managing aging the LRA does not address fire dampers in the

effects. LRA Section A.2.2.15 do not address fire dampers program elements like that in LUM00020-and LRA Section B.2.3.15 only includes OE on a degraded REPT-052.

gravity damper in the fire water pump house.

Is there a procedure for fire damper functional Section 3.1 of LUM00020-REPT-052 states a principal testing?

objective of the Fire Protection program is to conduct periodic visual inspection of fire dampers. Fire dampers are Please discuss whether the gravity damper is further addressed in several program element sections in this installed for fire protection and provide document (Sections 4.1.2, 4.3.2, 4.4.2, 4.5.2, and 4.6.2). In information on where the damper was worn.

addition, Procedure No. MSM-P0-0705 is for fire damper inspection and cleaning. This procedure does not include fire damper functional testing.

The staff notes that NUREG-2191, Generic Aging Lessons Learned for Subsequent License Renewal (GALL-SLR)

Report, addresses fire dampers (AMR items, program description, and FSAR supplement).

LRA Section B.2.3.15 and LUM00020-REPT-052 includes operating experience related to a degraded gravity damper.

CR-2012-006446 states that the suspected cause was age and wear, and that the damper was worn, however, it does not state where the damper was worn (e.g., damper housing).

5 3.5 3.5-185 LRA Table 3.5.2-15 includes galvanized steel commodity Given that AMR Item 3.3-1, 059 is for door and cites AMR Items 3.5-1, 095 (indoor uncontrolled managing loss of material due to wear of air, non) and 3.3-1, 059 (outdoor air, loss of material, Fire steel fire rated doors exposed to indoor Protection program), and 3.5-1, 089 (air with borated water uncontrolled air and outdoor air, please leakage, loss of material, Boric Acid Corrosion program). discuss use of AMR Item 3.5-1, 095 for galvanized steel commodity doors exposed to indoor uncontrolled air.

6 3.5 3.5-187 LRA Table 3.5.2-15 includes silicate radiant energy shield, Please discuss where these insulations and subliming compound, ceramic fiber/blanket, and stainless wraps, penetration seals, and penetration steel insulation and wrap exposed to outdoor air. This table sleeves are located to be exposed to outdoor also includes elastomer penetration seals and carbon steel air. If these fire barriers are not protected from

and stainless steel penetration sleeves exposed to outdoor weather, please discuss any impacts on the air. aging effects to be managed.

Loss of material of the stainless steel insulation and wrap and Please discuss what the specific ceramic penetration sleeve exposed to outdoor air in LRA Table 3.5.2- fiber/blanket materials are.

15 are managed by the Structures Monitoring program (AMR Item 3.5-1, 093) and cites plant-specific Note 5, which states, Please discuss how the Structures Monitoring Relative to stainless-steel components located outdoors, the program is adequate to manage the aging Structures Monitoring (B.2.3.34) AMP is focused on areas effects for the stainless steel insulation and with potential for frequent or prolonged water pooling and wrap and penetration sleeve to ensure the communicates with the Fire Protection (B.2.3.15) AMP as Fire Barrier intended function is maintained.

warranted. Please discuss how the program descriptions This plant-specific note does not provide details on how the and procedures for the Structures Monitoring Structures Monitoring program is adequate to manage the and Fire Protection programs reflect this.

aging effects for the stainless steel insulation and wrap and penetration sleeve to ensure the Fire Barrier intended function is maintained.

The staff notes that the discussion of AMR Item 3.5-1, 093 states, For stainless steel and aluminum, the focus is on areas where water could pool or get within insulation jacketing.

The staff did not find information related to these stainless steel insulation and wrap and penetration sleeve in Structures Monitoring or Fire Protection program descriptions or documents on the portal.

7 3.5 3.5-188 LRA Table 3.5.2-15 includes masonry block commodity wall, Please discuss whether both the Masonry floor, and ceiling with a fire barrier intended function Walls and Fire Protection programs will managed by the Masonry Walls program. Like Question manage the masonry block commodity wall, Number 3, the Fire Protection program was not cited for this floor, and ceiling.

masonry block commodity.

The staff notes that LRA Section 3.5.2.2.2.2 cites only the Masonry Walls program for managing the fire bricks and mortar.

8 3.5 3.5-189 LRA Table 3.5.2-15 includes gypsum fire barrier walls, floors, Please discuss how the Fire Protection and ceilings exposed to indoor uncontrolled air and cites the program is adequate for managing the aging Fire Protection program for managing cracking, loss of bond, effects for the rated gypsum drywall to ensure and loss of material. The table includes no NURE-1801, the Fire Barrier intended function is Revision 2 or Table 1 Items and includes generic note F, maintained. Provide rating (hours) of gypsum Material not in NUREG-1801 for this component, and plant- drywall fire barrier.

specific note 4, Gypsum drywall is utilized throughout the plant to provide a fire barrier which is lightweight and where unit masonry or concrete is not feasible.

This lightweight fire barrier material is not addressed in NUREG-1801; however, aging is managed by the Fire Protection (B.2.3.15) AMP. This plant-specific note does not provide why the Fire Protection program is adequate to manage the aging effects for the gypsum drywall.

9 A.2.2.15 A-18 LRA Sections A.2.2.15 and B.2.3.15 state that the Fire Please verify that 100 percent of each type of and and B- Protection program includes visual inspections of 100 penetration fire seal every 15 years also B.2.3.15 103 percent of each type of penetration fire seal every 15 years. meets not less than 10 percent of each type LRA Section A.2.2.15 goes on to state that the visual of penetration fire seal.

inspections of penetration fire seals are in accordance with the plants NRC-approved fire protection program. Please identify the reference that states visual inspections of 100 percent of each type The Parameters Monitored/Inspected and Detection of Aging of penetration fire seal every 15 years is in Effects program elements in Rev. 2 of NUREG-1801 state accordance with the plants NRC-approved that not less than 10% of each type of seal are to be visually fire protection program. Does this document inspected at a frequency in accordance with an NRC- also have a similar statement related to the approved fire protection program or at least once every frequency of visual inspections of fire door refueling outage. surfaces and function testing of fire doors (see LRA Section A.2.2.15)?

10 N/A N/A Section 3.3 in Revision 1 of LUM00020-REPT-052 states that Please discuss whether there are drip shields Structures Monitoring AMP will manage drip shields and like those at Turkey Point at Comanche Peak references Revision 1 of LUM00020-REPT-071. However, or other drip shields that are to be managed Revision 1 of LUM00020-REPT-071 does not address drip by the Structures Monitoring AMP. If there shields. The LRA does not explicitly address drip shields. are, please discuss where the drip shields are However, the LRA does include drip pans for the RCS oil addressed in the LRA.

spillage collection (Fire Protection System) and drip pans for

certain ventilation systems. The staff notes that none of the drip pans addressed in the LRA are managed by the Structures Monitoring AMP.

11 N/A N/A Section 6.1 of EPRI 3002013084, Long-Term Operations: Please discuss whether materials are used to Subsequent License Renewal Aging Effects for Structures secure fire wraps. If so, please discuss where and Structural Components (Structural Tools), November they are addressed in the LRA, including 2018, states, in part, wire and other appurtenances used to AMR items for managing applicable aging secure fire wrap to the item being protected - is considered to effects.

be part of the fire wrap itself.

It is unclear from the staffs review of the available information whether there are materials used for securing fire wraps.

12 N/A N/A Procedure FIR-311 is related visual inspection of fire rated Please discuss whether the procedure will be assembly (Thermo-lag, radiant energy shield, and walls, updated to reflect the aging effects identified floors, and ceilings). Sections 8.2.3, 8.3, and 8.4.3 state to in the LRA.

verify no signs of degradation or damage and provides signs of degradation or damage to look for. However, other than cracks for Thermo-lag, the aging effects in the LRA for these fire barriers, are not provided as signs of degradation or damage to look for.

13 N/A N/A Sections 4.3.2, 4.5.2, and 4.6.2 of LUM00020-REPT-052 use Please discuss what is meant by abnormal the phrase abnormal degradation. degradation.

14 N/A N/A The Monitoring and Trending program element for the Fire Please discuss how the inspection results for Protection program in NUREG-1801, Revision 2 states that fire barriers will be trended for future actions.

the inspection results for penetration seals, fire barriers, and doors are trended for future actions and periodic tests of the halon fire suppression system provides data for trending.

LRA Sections A.2.2.15 and B.2.3.15 do not address trending of inspection results. Section 4.5.2 of LUM00020-REPT-052 states, The halon system is evaluated and trended by the Fire Protection Strategic Engineering Engineer [Ref.

9.2 Section 6.4]. However, for fire barriers, it only addresses

documenting the discovered condition, nothing on trending the results for future actions.

In addition, FIR-310 and FIR-311 do not address trending the results for future actions.

15 N/A N/A FIR-310 Sections 8.2.4.2 and 8.2.5.2 states to document Please discuss whether inspection results of penetration seals that are inaccessible and that inaccessible similar penetration seals are used to gain penetration seals are not required to be visually inspected. inform the possible condition of the inaccessible seals.

It is not clear if procedures include looking at similar penetration seals that would be representative of the inaccessible seals to determine if additional action should be taken with regard to the inaccessible seals.

16 N/A N/A FIR-310 includes width, depth, and length limits for gaps, Please discuss the basis for the width, depth, cuts, rips, gouges, tears, cracks in Type 1, Type 5, and Type 9 and length limits for penetration seals.

seals. In addition, MSG-1018 includes depth limits on cuts when installing seals. However, these documents do not appear to include the basis or the reference containing the basis for the length and width limits.

17 N/A N/A The NOTE for Section 8.10 in MSG-1018 states when Please clarify whether previously acceptable repairing seal damage or rework existing penetrations, the installed condition means the original penetration is to be returned to the previously acceptable installed condition that was analyzed for the installed condition. specific application?

Comanche Peak Nuclear Power Plant, Units 1 and 2 License Renewal Application (LRA) Breakout Audit Questions LRA Section AMP B.2.3.28: Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks Question LRA LRA Background / Issue Discussion Question / Request Number Section Page (As applicable/needed) 1 B.2.3.28 B-167 Exception No. 2 states the following (in part): The staff requests a generic discussion on the following exception, with a focus on the

  • The SI [safety injection] Pump Lubricating Oil following areas:

Reservoirs are internally lined. CPNPP samples the lubricating oil quarterly, and the system includes an oil

  • Type of lining used in the SI pump filter to remove debris and particulates prior to oil lubricating oil reservoirs.

reaching the bearings. The oil filter is cleaned quarterly as part of the lubricating oil sampling activities.

  • Specifications related to the oil filter (e.g., mesh size).
  • This alternate approach has been identified and accepted in an early LRA where that facility had a
  • Discussion of NRC precedent (the similar arrangement for SI pump lube oil reservoirs. ML number referenced in the LRA (Reference ML1582A051). does not produce any hits in ADAMS).

2 A.2.2.28 A-24 LRA Section A.2.2.28, Internal Coatings/Linings for In-Scope 1. The staffs understanding is that the Piping, Piping Components, Heat Exchangers, and Tanks, use of the phrase may be (in bold states [f]or coated/lined surfaces determined to not meet the and italicized to the left) is linked to acceptance criteria, physical testing may be performed in language in Exception No. 4. The conjunction with repair or replacement of the coating/lining. staff requests a discussion to confirm.

SRP-SLR Table 3.0-1, FSAR Supplement for Aging Management of Applicable Systems, states the following: 2. The staff requests a discussion with respect to why the training and

  • [f]or coated/lined surfaces determined to not meet the qualification of individuals involved in acceptance criteria, physical testing is performed cementitious linings inspections is not where physically possible (i.e., sufficient room to addressed in LRA Section A.2.2.28 (given that the program scope

conduct testing) in conjunction with repair or includes cementlined ductile iron replacement of the coating/lining. piping).

  • [f]or cementitious coatings, training and qualifications are based on an appropriate combination of education and experience related to inspecting concrete surfaces.

3 2.3.4.4 2.3-153 FSAR Section 10.4.5, Circulating Water System, states [t]he The staff request a discussion with respect circulating water system is composed of stainless steel, to if the subject components referenced in plastic, and carbon steel piping. Piping which is stainless steel, the FSAR are in-scope for license renewal.

plastic, or carbon steel less than or equal to 2" in diameter is unlined. Carbon steel piping 21/2" in diameter and larger is epoxylined. The main condenser water boxes are epoxylined.

LRA Section 2.3.4.4, Main Turbine and Auxiliaries System, states [t]here are no CW [circulating water] system mechanical components subject to AMR.

4 N/A N/A GALL Report AMP XI.M42 states for piping, either inspect a The staff could not identify where sample representative sample of 73 1-foot axial length circumferential size is addressed in either the LRA or segments of piping or 50 percent of the total length of each program basis document on the ePortal.

coating/lining material and environment combination, whichever is less.

Comanche Peak Nuclear Power Plant, Units 1 and 2 License Renewal Application (LRA) Breakout Audit Questions LRA Section AMP B.2.3.20: Selective Leaching Question LRA LRA Background / Issue Discussion Question / Request Number Section Page (As applicable/needed) 1 N/A N/A N/A Operating experience (OE) keyword list includes degraph. In addition, the staff requests graphiti. This would capture graphitic corrosion and graphitization.

2 N/A N/A LUM00020-REPT-057 (program basis document for the The staff request a discussion with respect to Selective Leaching program on the ePortal) allows for the scope of cathodically protected buried elimination of selective leaching inspections for gray cast components susceptible to selective leaching.

iron components that have been effectively protected by cathodic protection.

Buried components within the scope of the Selective Leaching program include the following: (a) gray cast iron valve bodies and fire hydrants; and (c) cementlined ductile iron piping.

3 N/A N/A LUM00020-REPT-057 allows for elimination of selective GALL Report AMP XI.M41 allows for the leaching inspections for buried components where visual elimination of selective leaching inspections for examinations of inscope buried piping have not revealed buried components where visual examinations any coating damage. of in-scope buried piping have not revealed any coating damage. Given the subject OE, OE Example No. 2 (for the Buried and Underground Piping the staff request a clarifying discussion with and Tanks AMP) states [i]n April of 2015, an opportunistic respect to why this exclusion is applicable at inspection was performed during the excavation process for Comanche Peak.

a potable water leak which exposed Fire Protection piping.

The inspection noted coating (coal tar wrap) damage. The inspection noted construction dunnage still in place under the pipe, which is not in compliance with the requirements

of 2323-SS-008, CPSES Excavation and Backfill Specification.

4 N/A N/A FSAR Section 4.5, Reactor Materials, states [t]he coil The staff request a clarifying discussion with housings require a magnetic material. Both low carbon cast respect to if the ductile iron coil housings steel and ductile iron have been successfully tested for this referenced in the FSAR are inscope for license application. The choice, made on the basis of cost, renewal.

indicates that ductile iron will be specified on the control rod drive mechanism (CRDM).

Comanche Peak Nuclear Power Plant, Units 1 and 2 License Renewal Application (LRA) Breakout Audit Questions LRA Section AMP B.2.3.24: Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Question LRA LRA Background / Issue Discussion Question / Request Number Section Page (As applicable/needed) 1 B.2.3.24 B-149 SLRA Section B.2.3.24, Inspection of Internal Surfaces in The subject recommendations come from Miscellaneous Piping and Ducting Components, states guidance in GALLSLR; however, surface A.2.2.24 A-22 [t]his AMP will also be used to manage cracking due to examinations or VT-1 examinations are SCC in stainless steel components exposed to aqueous specified. The staff request a discussion with solutions. Periodic visual inspections or surface respect to why VT-1 examinations are not examinations may be conducted to manage cracking every specified.

10 years during the PEO. Visual inspections will be conducted in lieu of surface examinations only when the visual inspection methods have been shown to be capable of detecting cracking.

SLRA Section A.2.2.24, Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components, states

[s]urface examinations or visual inspections methods shown to be capable of detecting cracking, such as VT-1 examinations, will be conducted to detect cracking of stainless steel components.

2 B.2.3.24 B-150 Operating Experience (OE) Example No. 1 states [t]he The staff requests a discussion on the subject fourth quarter of 2020 Vents & Drains system health report OE and whether it is representative of the identified a material condition within the system. A pipe condition of inscope piping at Comanche Peak.

segment located within the AB was identified with multiple pin hole leaks in various locations.

The staff noted several instances of throughwall leaks in vents and drains system piping during its audit.

3 Table 3.3.2- 3.3-178 LRA Table 3.3.2-5 states loss of material for aluminum Based on SLR guidance documents, cracking 5 pump casings exposed to waste water will be managed by may be an aging effect requiring management the Inspection of Internal Surfaces in Miscellaneous Piping (see SRPSLR Section 3.3.2.2.8, Cracking Due and Ducting Components program. The AMR item cites to Stress Corrosion Cracking in Aluminum generic note G. Alloys.) The staff requests a discussion on whether cracking should also be cited for this material and environment combination.

4 Table 3.3.2- 3.3-197 LRA Table 3.3.2-7 states hardening, loss of strength, and Based on its review of SLR guidance 7 loss of material for elastomer flexible hoses exposed to documents, the staff requests a discussion on waste water will be managed by the Inspection of Internal whether flow blockage due to fouling should Surfaces in Miscellaneous Piping and Ducting also be cited for this material and environment Components program. The AMR items cite generic note combination.

G.

5 Table 3.3.2- 3.3-282 LRA Table 3.3.2-12 states loss of material for PVC piping Based on its review of SLR guidance 12 exposed to raw water will be managed by the Inspection of documents, the staff requests a discussion on Internal Surfaces in Miscellaneous Piping and Ducting whether flow blockage due to fouling should Components program. The AMR item cites generic note also be cited for this material and environment G. combination.

Comanche Peak Nuclear Power Plant, Units 1 and 2 License Renewal Application (LRA) Breakout Audit Questions LRA Section N/A: Aluminum Question LRA LRA Background / Issue Discussion Question / Request Number Section Page (As applicable/needed) 1 Table 3.3.2- Page LRA Table 3.3.2-8c, Miscellaneous Ventilation Systems - This material and environment combination 8c 3.3-240 Summary of Aging Management Evaluation, states that is not addressed in LR guidance documents; aging effects for aluminum fan housings exposed to outdoor however, it is addressed in SLR guidance air are not applicable and no AMP is proposed. The AMR documents. Guidance with respect to items cite generic note I. whether cracking and loss of material are applicable aging effects for aluminum are contained in SRP-SLR Sections 3.3.2.2.8, Cracking Due to Stress Corrosion Cracking in Aluminum Alloys, and 3.3.2.2.10, Loss of Material Due to Pitting and Crevice Corrosion in Aluminum Alloys. The staff requests a discussion with respect to why aging effects are not applicable for the subject components.

Comanche Peak Nuclear Power Plant, Units 1 and 2 License Renewal Application (LRA) Breakout Audit Questions LRA Section N/A: Titanium Question LRA LRA Background / Issue Discussion Question / Request Number Section Page (As applicable/needed) 1 N/A N/A FSAR Section 10.4.1.1.2, System Description, states FSAR Chapter 10, Steam and Power

[t]he titanium used in the condenser tubes has good Conversion System, includes several references erosion and steam impingement resistance. to titanium components. Based on the staffs review of the LRA, there are no inscope titanium FSAR Section 10.4.1.1.3, Safety Evaluation, states components at Comanche Peak. Staff request a

[t]he main condenser tube bundles and tube sheet clarifying discussion with respect to if there are assemblies are constructed of titanium and titanium clad inscope titanium components at Comanche carbon steel respectively. Peak.

FSAR Section 10.4.5.2, System Description, states

[t]itanium tubes are used throughout the condenser tube bundle assemblies in both the air removal and condensing sections.

Comanche Peak Nuclear Power Plant, Units 1 and 2 License Renewal Application (LRA) Breakout Audit Questions LRA/SLRA Section /TLAA/AMP/Scoping and Screening:

Question LRA/SLRA LRA/SLRA Background / Issue Discussion Question / Request Number Section Page (As applicable/needed)

  1. 1 Report Number 11/38 Exception 1: The EDG DFOSTs are drained, cleaned, Under NUREG-1801, Rev 2 the 10-year interval LUM00020- visually inspected, and ultrasonically was considered an acceptable duration such REPT-055 that any unforeseen degradation mechanism XI.M30 Fuel inspected on a 20-year frequency per Preventive would be identified prior to challenging tank Oil Chemistry Maintenance (PMs). NUREG-1801, Rev. 2 guidance integrity.

recommends draining, cleaning and visually inspecting (Comanche each diesel fuel tank at least While previous inspections have not identified Peak Nuclear historical corrosion or wall thinning. Can you Power Plant once during the 10-year period prior to the PEO, and please explain to the NRC staff in detail on a 10-year frequency during the PEO. including drawings (and/or graphics, Units 1 and 2 presentation) why this does not preclude a new License or more aggressive degradation mechanism Renewal from occurring during the period of extended Application operation?

Basis Document) Also, based on the description of exception #2, there could be 5 or more inches of standing water in the bottom of the tank, and it could exist for long periods of time without being identified.

Do you think this could be one potential source of degradation that would only be identified by a full draining and examination of the tank?

  1. 2 Report Number 12/38 Exception 2: The CPNPP Fuel Oil Chemistry AMP Under NUREG 1801, Vol. 2, the alternative LUM00020- collects fuel oil samples from the lower portion (6 sampling method allowed by GALL calls for a REPT-055 inches from the bottom) of the EDG DFOSTs on a 31- sample from the lowest point in the tank. The day frequency. NUREG-1801 Rev. 2 guidance sampling point proposed by Comanche Peak is

XI.M30 Fuel recommends periodic multilevel sampling to provide 6 inches above the tank bottom. Please explain Oil Chemistry assurance that fuel oil contaminants are below clearly to the NRC staff how this sample would unacceptable levels. If tank design features do not identify a layer of water, microorganism, and/or (Comanche allow for multilevel sampling, a sampling methodology contamination on the tank bottom?

Peak Nuclear that includes a representative sample from the lowest Power Plant point in the tank is allowed. The sample at Comanche Peak will being taken by lowering a thief into the tank. Why is 6 Units 1 and 2 Previously, the bottom sample methods not at the inches as close to the bottom as you can get?

License lowest portion of the tank were approved, if the Given the size of the tank Please, explain in Renewal applicant was able to show that there was a set of detail (using drawings and/or graphics, Application sampling points (pipe and valves) and this was the only presentation). Do you think it would be possible Basis way to access a sample. In addition, the applicant was whether any flow would occur prior to sampling Document) able to show that significant flow and tank turnover that would mix a water layer into the tank level occurred such that any water would be mixed into the where a sample is taken?

sample taken from a location several inches away from the lowest point in the tank.

Comanche Peak Nuclear Power Plant, Units 1 and 2 License Renewal Application (LRA) Breakout Audit Questions LRA Section AMP B.2.3.11: Open Cycle Cooling Water System Question LRA LRA Background / Issue Discussion Question / Request Number Section Page (As applicable/needed) 1 B.2.3.11 B-89 SLRA Section B.2.3.11, Open Cycle Cooling Water (OCCW) The listed TRs and CRs appear to AMP states that recurring internal corrosion (RIC) has not been contradict the statement that recurring identified for components within the scope of the OCCW AMP. This internal corrosion is not occurring at section further states that CPNPPs response to IER L3 1453 was CPNPP. The staff requests discussion on to review the set of plant-specific OE for ten years prior for the cited TRs and CRs as to why they do evidence of thru-wall pipe leaks in class 3 SSW piping and no not provide evidence that RIC is leaks were identified during that time period. occurring at CPNPP.

  • TR-2021-005356 - leak at circulating water lube pumps leaking at several gallons per minute (gpm).
  • TR-2020-9117 - the end bell of the 2-02 component 3.3.2.2.8 3.3-25 cooling water heat exchanger (HX) was leaking on the station service water side at approximately 5 gpm.
  • CR-2019-002492 - A pencil-sized stream of leakage observed from the 2-01 component cooling water HX while 2SW-0023 was throttled to obtain test pressure.
  • CR-2016-4868 - After completion of maintenance to clean CCP 101 lube oil cooler, a service water leak was discovered coming from significant pitting of the flange sealing surface of the cooler end bell. This pitting also documented previously in CR-2014-1804.
  • More flange pitting documented in CR2020-7876, CR20207762, & CR201112880.

SLRA Section 3.3.2.2.8, Loss of Material due to Recurring Internal Corrosion (Per LR-ISG-2012-02) states, Corrosion in the

SSW meets the criteria to be considered RIC based solely on number of instances. However, no minimum wall thickness criteria were exceeded. Reduction in wall thickness has been monitored at a frequency to sufficiently identify any issues. Based on the monitoring, the CPNPP SSW does not meet criteria for extent of degradation.

  • CR-2016-4786 - While performing work order 5042345, it was noted that five nodule corrosion areas were below the minimum acceptable pipe wall thickness.

2 2.4.8 2.4-22 SLRA Section 2.4.8, Service Water Intake Structure states, The staff would like to discuss Traveling screens perform their function with moving parts, are documenting the current inspections that active and are not subject to AMR. are performed during operator rounds and how those inspections could be used The traveling screens provide filtration, which is defined as a as an aging management inspection for passive function in Table 2.1-4(b) of the SRP. Traveling screens loss of material in the traveling screens.

are typically monitored for high differential pressure, but they typically do not have a low differential pressure indication, which is what would be needed to accomplish an inspection function to verify there was not a large hole in the screens that would allow debris to pass through the screen.

Comanche Peak Nuclear Power Plant, Units 1 and 2 License Renewal Application (LRA) Breakout Audit Questions LRA Section: B.2.3.16 Question LRA LRA Background / Issue Discussion Question / Request Number Section Page (As applicable/needed) 1 2.3 2.3-81 LRA Section 2.3.3.7 states, The diesel engines for fire Please discuss revising the LRA (including pumps and the engine mounted components are part of the drawing DDMEC_MX-0225_009_CP11-LR) to active engine assembly. These active components are not include the heat exchangers, water jacket subject to AMR. The exhaust piping, exhaust silencer, flame coolers, and flex connections associated with arrestor and heat exchanger are subject to AMR [emphasis the fire pump diesel engines in accordance added]. with industry guidance.

Drawing DDMEC_MX-0225_009_CP11-LR shows a water jacket cooler and flex connection highlighted in green which means these components are subject to AMR. However, the drawing also has a LR Note that states, Diesel Engines and Water Jacket Cooler are Complex Assemblies Per NEI 95-10 and are not Subject to AMR.

The staff noes that NEI 95-10, Reference 12 states: if a nonsafety-related diesel generator is required for safe shutdown under the fire protection plan, the diesel generator and all SSCs specifically required for that diesel to comply with and operate within the Commissions regulations based on the applicants design specifications for that diesel shall be included within the scope of license renewal under 10 CFR 54.4(a)(3). This may include, but should not be limited to the cooling water system or systems required for operability, LRA Table 3.3.2-7 includes several components associated with the fire pump diesel engines. However, it does not

appear to include heat exchangers, water jacket coolers, or flex connections.

2 3.3 3.3-206 LRA Table 3.3.2-7 includes component type Strainer Please clarify the information presented in the (Electric motor driven pump suction). However, LRA LRA with regards to fire pump suction strainers Sections A.2.2.16 and B.2.3.16 state, in part, There are no and screens.

fire pump suction strainers for the main fire protection pumpswithin the scope of LR.

The staff notes that the Fire Water System Inspections and Tests table in LRA Section B.2.3.16 states, The Fire Pumps receive treated water and do not have suction screens.

3 2.4.11 2.4-28 LRA Section 2.4.11 states, The tanks are provided with a Please discuss why LRA Table 3.3.2-7 does reinforced concrete ring wall type foundation below the tank not include concrete and sand or soil external walls. environments for the fire water storage tank.

The Discussion of AMR Item 3.3-1, 128 in LRA Table 3.3-1 Please discuss where the LRA addresses use states, In addition, the Fire Water System (B.2.3.16) AMP (and inspection) of sealant or caulking at the includes enhancement to address the steel/concrete steel/concrete interface.

interface.

Please discuss the use of AMR Item 3.3-1, 136 LRA Table 3.3.2-7 does not address Tank (Fire Water for internally coated/lined fire water storage Storage) exposed externally to concrete. The concrete ring tanks.

wall type foundation typically has sand or soil inside the ring that provides support to the tank bottom, however, LRA Please discuss the basis for only performing Table 3.3.2-7 does not address Tank (Fire Water Storage) bottom-thickness measurements on each tank exposed externally to sand or soil. In addition, the LRA does during the first 10-year period of the period of not appear to address the use (and inspection) of sealant or extended operation and when there is caulking at the steel/concrete interface to mitigate tank evidence of pitting or corrosion.

corrosion.

LRA Table 3.3.2-7 cites AMR Item 3.3-1, 136 with a Generic Note B for managing loss of material of the carbon steel with internal coating/lining tank (Fire Water Storage) exposed internally to treater water. However, AMR Item 3.3-

1, 136 does not address internally coated/lined fire water storage tanks.

The staff notes that Fire Water System Inspections and Tests table in LRA Section B.2.3.16 states, In addition, the new plant implementing document will require bottom-thickness measurements on each tank during the first 10-year period of the period of extended operation. Tank bottoms will be tested for metal loss and/or rust on the underside by use of ultrasonic testing where there is evidence of pitting or corrosion. Removal, visual inspection, and replacement of random floor coupons are an acceptable alternative to ultrasonic testing.

The staff notes that XI.M29 in NUREG-1801 addresses tank bottoms exposed to concrete. Specifically, to ensure loss of material is not occurring at inaccessible locations, ultrasonic testing thickness measurements are taken whenever the tank is drained and at least once within 5 years of entering the period of extended operation. The staff notes that NUREG-2191 also points to XI.M29 for tank bottoms exposed to concrete. Table XI.M29-1 states that loss of material is managed for steel external surfaces exposed to soil or concrete by performing volumetric inspections from the inside surface each 10 year period starting 10 years before the subsequent period of extended operation.

It is unclear to the staff how performing the bottom-thickness measurements during the first 10-year period of extended operation and when there is evidence of pitting or corrosion meets the guidance in NUREG-1801 and NUREG-2191 related to fire water storage tank bottoms exposed to concrete.

4 3.2.2.2.9 3.2-11 LRA Section 3.2.2.2.9 states, As such, credited AMPs, Please discuss whether the Fire Water System such as Fire Water, Inspection of internal Surfaces in should have been referenced in LRA Section Miscellaneous Piping and Ducting Components, and Open 3.2.2.2.9.

cycle Cooling Water, do not require enhancement to

address RIC in ESF systems. However, LRA Tables 3.2.2-1 through 3.2.2-5 do not credit the Fire Water System program with managing components in any ESF systems.

5 A.2.2.16 A-18 The Scope of Program program element of LR-ISG-2013- Please discuss the omission of statements 01 states, However, where the fire water storage tank regarding personnel evaluating degradation internals are coated, the Fire Water System Program and and corrective actions from LRA Section FSAR Summary Description of the Program should be A.2.2.16.

enhanced to include the recommendations associated with training and qualification of personnel and the corrective actions program element [emphasis added]. The Detection of Aging Effects program element of LR-ISG-2013-01 states, The training and qualification of individuals involved in coating/lining inspections and evaluating

[emphasis added] degraded conditions is conducted in accordance with an ASTM International standard endorsed in RG 1.54 including staff limitations associated with a particular standard, except for cementitious materials.

LRA Section A.2.2.16 does not include statements regarding the training and qualification of personnel evaluating degraded conditions and it does not include statements regarding the corrective actions recommendations.

6 A.2.2.16 A-18 LRA Sections A.2.2.16 and B.2.3.16 state, The augmented Please discuss whether recurring internal and and B- examinations for the portions of normally dry piping that are corrosion is occurring in the Fire Protection B.2.3.16 106 periodically wetted or experiencing recurring internal System. In addition, please discuss each corrosion [emphasis added] include (a) periodic full flow identified CR and TR to demonstrate whether tests at the design pressure and flow rate, or internal it is or is not pressure boundary internal inspections, and (b) volumetric wall thickness evaluations. corrosion.

LRA Section B.2.3.16 also states, The review did not identify instances of recurring internal corrosion within the fire protection systems. However, LRA Section 3.3.2.2.8 states that recurring internal corrosion is not applicable for Auxiliary Systems, including the Fire Water System. The Discussion for AMR Item 3.3-1, 127 in LRA Table 3.3-1

states, Not applicable. Loss of material due to recurring internal corrosion has not been identified in metallic piping, piping components, and tanks exposed to raw water or waste water in the auxiliary systems. Finally, LRA Table 3.3.2-7 does not cite AMR Item 3.3-1, 127 for any components in the Fire Protection System.

Operating experience reviews identified the following reports of leakage, but it is not clear whether these are pressure boundary leaks caused by internal corrosion:

  • TR-2021-007722, Nov-12-2021, Leakage rate for 2FP-0493C has risen to 0.12 gpm
  • TR-2021-007069, Oct-23-2021, Leaking FW riser
  • TR-2021-004976, Jul-28-2021, X-HV-4107D leaking from Retard Chamber
  • TR-2021-004964, Jul-28-2021, XFP-0595 leak rate of 5-6 dpm
  • CR-2021-001386, Feb-23-2021, 5dpm leak on FP line
  • CR-2021-001377, Feb-23-2021, FP leak in Admin Bldg
  • TR-2021-001032, Feb-09-2021, Pin hole leak in 2.5-inch sprinkler pipe
  • CR-2017-005038, Apr-15-2017, Fire suppression pipe has a slow leak
  • CR-2014-000046, Jan-3-2014, Leak on side of elbow downstream of 1FP-0093E
  • CR-2012-005114, May-18-2012, Water dripping from strainer Therefore, it is unclear to the staff whether recurring internal corrosion is an applicable aging effect for the Fire Protection System.

7 B.2.3.16 B-106 Appendix L of LR-ISG-2012-02 states that portions of water- Please identify which portions of the fire based fire protection system components that have been protection system are subject to augmented wetted but are normally dry are subject to augmented tests testing or inspection because they are or inspections. In addition, LRA Section B.2.3.16 includes normally dry but periodically subjected to flow an enhancement to perform augmented tests and and cannot be drained or allow water to inspections on piping segments that cannot be drained or collect.

collect water. However, the staff did not find where the portions subject to augmented testing or inspection were identified.

8 B.2.3.16 B-114 Appendix L of LR-ISG-2012-02 recommends that main To identify whether significant degradation of drain tests follow Section 13.2.5 of NFPA 25. Section 13.2.5 the fire water system supply has been of NFPA 25 requires main drain tests to be conducted occurring over several years, please discuss annually at each water-based fire protection system riser to whether test results will also be compared to determine whether there has been a change in the the original acceptance test (or baseline). If a condition of the water supply piping and control valves. It baseline, please provide discussion of how also states, When there is a 10 percent reduction in full that baseline was determined.

flow pressure when compared to the original acceptance test or previously performed tests [emphasis added], the cause of the reduction shall be identified and corrected if necessary.

Fire Water System Inspections and Tests table in LRA Section B.2.3.16 states, Test results will be compared to previous results [emphasis added] to determine if there has

been a 10% or greater reduction in full flow pressure, and if there is, the issue will be entered into the CAP and the cause of the reduction will be identified and corrected, as necessary.

The staff notes that if the test-to-test pressure monitoring only uses the immediately prior test result, significant degradation of the fire water system supply over several years may not be identified while still being less than a 10 percent reduction from the previous test.

9 B.2.3.16 B-106 The Acceptance Criteria program element in NUREG-1801 Please discuss the differences in the states, in part, (b) no unacceptance signs of degradation Acceptance Criteria in LRA Section B.2.3.16 are observed during non-intrusive or visual inspection of from NUREG-1801.

components, (c) minimum design pipe wall thickness is maintained, (d) no biofouling exists in the sprinkler systems that could cause corrosion in the sprinklers.

LRA Section B.2.3.16 states, in part, (b) no unacceptable signs of degradation or fouling are observed during nonintrusive or visual inspections, and (c) in the event surface irregularities are identified, testing is performed to ensure minimum design pipe wall thickness is maintained.

The guidance does not include fouling in Acceptance Criteria (b) but in Acceptance Criteria (d), which is not included in LRA Section B.2.3.16. In addition, Acceptance Criteria (c) in LRA Section B.2.3.16 does not appear to take into account thickness measurements performed on periodically wetted but normally dry pip and fire water storage tank bottoms.

10 3.3 3.3-199 LRA Table 3.3.2-7 cites AMR Item 3.3-1, 091 for managing Please discuss whether flow blockage is an loss of material for carbon steel piping exposed internally to applicable aging effect requiring management waste water. While AMR Item 3.3-1, 091 does not include for carbon steel piping exposed internally to flow blockage in NUREG-1800, Rev. 2, flow blockage is waste water.

included in this AMR item in NUREG-2191.

11 3.3 3.3-194 LRA Table 3.3.2-7 does not identify erosion as an applicable Please discuss whether any operational aging effect for any Fire Protection system components. experience related to erosion mechanisms, including cavitation, flashing, droplet impingement, or solid particle impingement have been identified.

12 N/A N/A Section 4.4.2 of LUM00020-REPT-053 states, If the Is the intent to assume what is occurring with environmental conditions (e.g., type of water, flowrate, the above grade fire protection piping that is temperature) and material that exist on the interior surface not cement lined is occurring with the buried of the underground and buried fire protection piping are cement lined ductile iron fire protection similar to the conditions that exist within the above grade piping?

fire protection piping, the results of the inspections of the above grade fire protection piping can be extrapolated to evaluate the condition of buried and underground fire protection piping for the purpose of identifying inside diameter loss of material. This section further states, With respect to buried cement lined ductile iron piping, the environmental and material conditions are similar to those above grade, with the exception that the ductile iron piping is cement lined.

13 N/A N/A Section 3.3 of LUM00020-REPT-053 states that the Turkey Please discuss whether sprinkler system flow Point RAI related to trending sprinkler system inspection tests are monitored and trended.

and tests results is applicable however, LR-ISG-2002-02 does not discuss trending of deposits. This section goes on Please discuss what parameters are/will be to state that buried and underground flow tests are monitored and trended for flow tests.

monitored and trended, and that the Fire Water System program will be enhanced to monitor and trend standpipe and hose system and main drain flow test results. It does not discuss whether monitoring and trending of sprinkler system flow tests are performed. It is unclear whether deposits are monitored and trended for any flow tests.

Comanche Peak Nuclear Power Plant, Units 1 and 2 License Renewal Application (LRA) Breakout Audit Questions LRA Sections 3.2.2.2.3.2, 3.2.2.2.6, 3.3.2.2.3, 3.3.2.2.5, 3.4.2.2.2, 3.4.2.2.3 Question LRA/SLRA LRA/SLRA Background / Issue Discussion Question / Request Number Section Page (As applicable/needed) 1 3.2.2.2.3.2, LRA further evaluation (FE) sections 3.2.2.2.3.2, For FE Sections 3.2.2.2.3.2, 3.2.2.2.6, 3.2.2.2.6, 3.2.2.2.6, 3.3.2.2.3, 3.3.2.2.5, 3.4.2.2.2, 3.4.2.2.3 state 3.3.2.2.3, 3.3.2.2.5, 3.4.2.2.2, 3.4.2.2.3, 3.3.2.2.3, that loss of material (LOM) due to pitting corrosion, please explain the criteria used in the LRA 3.3.2.2.5, crevice corrosion, and stress corrosion cracking (SCC) for determining whether or not stainless 3.4.2.2.2, do not require aging management because the outdoor steel components could be exposed to 3.4.2.2.3 air does not contain sufficient halide concentration and conditions potentially causing pitting, events that would increase the halide content are crevice corrosion, or SCC that require unlikely. management.

However, LRA Sections 3.2.2.2.3.2, 3.3.2.2.5, and 3.4.2.2.3 identify select instances where LOM due to pitting and crevice corrosion (but not SCC) of stainless steel is considered possible and managed by the External Surfaces Monitoring of Mechanical Components Aging Management Program. These include the top of the Condensate Storage Tank, Reactor Makeup Water Storage Tank, and Refueling Water Storage Tank. The discussions for these instances note that contaminants in outdoor air could collect on these components surfaces.

LRA guidance identifies criteria for determining if the presence of sufficient halides is likely (e.g., NUREG-1800, Rev. 2, Sections 3.2.3.2.3.2 and 3.2.3.2.6). However, SLR guidance states more broadly that LOM and SCC of stainless steel could occur in environments containing sufficient halides in

the presence of moisture (e.g., NUREG-2192, Sections 3.2.3.2.2 and 3.2.3.2.4).

2 3.2.2.2.3.2, 3.2-8 and 3.2- In LRA sections 3.2.2.2.3.2, 3.2.2.2.6, 3.3.2.2.3, For FE Sections 3.2.2.2.3.2, 3.2.2.2.6, 3.2.2.2.6, 9, for example 3.3.2.2.5, 3.4.2.2.2, 3.4.2.2.3 for stainless steel, in 3.3.2.2.3, 3.3.2.2.5, 3.4.2.2.2, 3.4.2.2.3, 3.3.2.2.3, cases where LOM due to pitting and crevice corrosion please discuss the basis for not considering 3.3.2.2.5, are considered aging effects requiring management stainless steel components susceptible to 3.4.2.2.2, (AERM), SCC is not considered an AERM. For SCC when they are considered susceptible 3.4.2.2.3 example, Section 3.2.2.2.3.2, Loss of Material due to to pitting and crevice corrosion.

Pitting and Crevice Corrosion, includes some cases where LOM for stainless steel in air is considered possible and is managed by the External Surfaces Monitoring of Mechanical Components Aging Management Program. However, LRA Section 3.2.2.2.6, Cracking due to Stress Corrosion Cracking, states that no stainless steel components exposed to air in ESF Systems require aging management for SCC.

3 3.2.2.2.6 3.2-9 LRA Section 3.2.2.2.6 contains a reference to Item 3.2- Please confirm the intended item where 1, 006, which applies only to BWRs. This appears to Item 3.2-1, 006 is used in Section 3.2.2.2.6.

be intended to reference 3.2-1, 007, which applies to FE Section 3.2.2.2.6 for SCC of stainless steel.

Comanche Peak Nuclear Power Plant, Units 1 and 2 License Renewal Application (LRA) Breakout Audit Questions LRA Section AMP B.2.3.12: Closed Treated Water Systems Question LRA LRA Background / Issue Discussion Question / Request Number Section Page (As applicable/needed) 1 B.2.3.12 B-94 LRA Section B.2.3.12, Closed Treated Water Systems (CTW) The 20% sample (max of 25) proposed AMP states that an evaluation performed in 2013 of through- inspection scope in the LRA matches the wall leaks in carbon steel Turbine Plant Cooling Water (TPCW) minimum inspection scope contained in the welds identified that the associated portion of the TPCW GALL-SLR for the CTW system, which is system was constructed with undersized welds and the proposed for verifying that the water degradation qualified as Recurring Internal Corrosion (RIC) chemistry program is adequately managing based on the guidance in LR-ISG-2012-02. The Closed aging in a CTW system.

Treated Water Systems AMP is being enhanced to include a 20% inspection of the in-scope TPCW welds (up to a max of As noted in Section 3.2.2.2.7 of the 25 welds) every 10 years during the period of extended SRPSLR, recurring internal corrosion can operation (PEO). result in the need to augment AMPs beyond the recommendations in the GALLSLR LR-ISG-2012-02 states the criteria for RIC is (a) a 10-year Report.

search of plant specific OE reveals the aging effect has occurred in three or more refueling outage cycles; or (b) a 5- Please discuss your technical basis for year search of plant specific OE reveals the aging effect has implementing the minimum inspection scope occurred in two or more refueling outage cycles as a result of and not expanding the sample (e.g., larger which the component either did not meet plant-specific sample size, more frequent inspections) acceptance criteria or experienced a reduction in wall since recurring internal corrosion has already thickness greater than 50 percent (regardless of the minimum been identified in the TPCW system.

wall thickness).

2 B.2.3.12 B-94 Additional operating experience in Section B.2.3.12 indicates Since the worst-case plugging projection that 25 percent of the TPCW heat exchanger tubes were predicted exceeding the plugging limit in just replaced in 2020, which reduced the number of plugged tubes 4 years (2020-2024), please discuss the from 289 to 240. An analysis determined a tube plugging limit best-case and nominal projections. Also, of 1,066 tubes, and the worstcase projection of future tube please discuss the cause of the tube plugging and your technical basis for

plugging predicts that the plugging limit of 1,066 tubes could implementing the minimum inspection scope be exceeded in 2024. and not expanding the sample, since recurring internal corrosion has already been identified in the TPCW system.

Comanche Peak Nuclear Power Plant, Units 1 and 2 License Renewal Application (LRA) Breakout Audit Questions LRA Section AMP B.2.3.8: Flow-Accelerated Corrosion Question Background / Issue Discussion Question / Request Number (As applicable/needed) 1 STA-170-1 Software QA Form for FAC Manager Discuss what are software QA requirements for both CHECWORKS and FAC Manager software.

Software is level 3 so SQA controls are minimal Both software suppliers appear to provide error reporting and validation A8.6 CPNPP will provide verification that the and verification by the vendors. Are these required by Level 3 software? If software has been procured in accordance with these are not required by CPNPPs Software QA requirements, is there a STA-151. Ensure error reporting will be provided by contractual requirement for the vendors to provide error reporting or supplier to appropriate Vistra personnel. validation and verification?

2 TR-2017-012206 From data obtained, the Provide documentation that showed acceptability of operation for 2 more component could operate for two full cycles before it cycles and discuss.

should be replaced.

Provide scope expansion information and discuss.

3 TR-2019-004795 identified thinning and component Provide documentation that showed acceptability of operation until the next would be replaced next outage; however, leak outage.

developed prior to outage and had to be temporarily repaired Since leak occurred prior to plan, what went wrong?

4 TR-2019-005126 Extent of condition for TR-2019- What is inspection priority of these lines per the Altran Report?

004731 added warm-up lines to CHECWORKS as susceptible non-modeled. States lines will be Initial leak was on a priority 2 line, that was not frequently inspected. Is inspected based on inspection priority established priority changed based on leak in TR-2019-004731?

per Altran Susceptibility Evaluation Tech Report 11- Did orifice location play a part in the rupture? If so, was susceptibility of 2235-TR-001, Rev 0. failure appropriately considered and do other lines with orifices (beyond the HD warm-up lines) need to be considered?

5 TR-2021-001032 discusses additional deficiencies Discuss whether this activity managing erosion was appropriately and extent of condition and notes that a cursory deactivated.

review of PMs deactivated by AI-TR-2019-008413-11 found that PM 344709 to measure pipe wall thickness in segments CO-2-071 was deactivated. The initial PM was created by CR-2002-002672 because of operational changes creating a region susceptible to erosion when SG Blowdown is aligned to the condenser hotwell.

6 2RF17 EOC Report for Cycle (May-2017 to Dec- EPG- 9.04 addresses issuance of EOC Reports but does not specify 2018) timeliness. Is 21 months acceptable? If not, was a TR written for this? Does additional guidance on EOC issuance timeliness need to be Report was issued in Sep-2020, 21(?) months after added to EPG-9.04?

the end of the cycle.

1RF20 EOC Report (Nov-6-2017 to Apr-20-2019)

[Prepared Sep-2020, Appvd Dec-2020, 17(?)

months after end of cycle.

7 TERPT ER-ME-093, Flow-Accelerated Corrosion Discuss how these systems are non-water systems.

System Susceptibility Analysis for Comanche Peak Unit 1, Rev 0, May 1995, Table 6.2 Non-susceptible systems The following were excluded based on NW non-water:

Chemical Volume and Control Containment Spray Residual Heat Removal Safety Injection 8 LUM00020-REPT-045, Rev 1, Flow-Accelerated The issue in the RAI and the Info Notice deals with legacy errors in the Corrosion (FAC) Program Basis Document, Section CHECWORKS models. Neither response in the basis document appear to 3.3, License Renewal RAI Responses discusses address the potential issue of legacy errors. Other than going back and Peach Bottom RAI B.2.1.9-2 relating to legacy errors checking orifice sizes, have there been any other activities to validate the

in CHECWORKS models. Response says existing CHECWORKS models that would be responsive to the issues in procedures will be enhanced to require that the RAI or Info Notice?

updates to predictive models are controlled and independently reviewed. Although response associated with the Peach Bottom RAI says the procedures will be enhanced, there are no enhancements associated with The RAI is based on Info Notice 2019-08, which is predictive model updates. The current program (EPG-9.04, Section 6.12) addressed in Program Basis Document Section only recommends that changes to the model be review but does not 4.10. Discussion states Both sites indicated that if appear to require this. Does there need to be an additional enhancement to their models within the FAC program had been the program procedures as stated?

accurately validated this [it] is possible these events could have been prevented.

9 LRA Table 3.3.2-12 Station Service Water System Discuss how wall thinning of PVC piping will be monitored by the FAC includes PVC piping being managed for wall program.

thinning through the Flow-Accelerated Corrosion Program.

Comanche Peak Nuclear Power Plant, Units 1 and 2 License Renewal Application (LRA) Breakout Audit Questions LRA Section: B.2.3.4 GALL AMP XI.M10 Boric Acid Corrosion Question LRA LRA Background / Issue Discussion Question / Request Number Section Page (As applicable/needed) 1 B.2.3.4 B-42 The LRA says no Enhancements to program. If the program basis document identifies changes to be made to the implementing Program basis document, LUM00020-REPT-042, Section 6 procedures (beyond being consistent with the Regulatory Commitments Including Any Enhancements and GALL) (with the implementation schedule tied Inspections, says the AMP does not require any enhancements to to PEO), then it appears that you have be consistent with the GALL AMP. However, Section 7, Summary identified enhancements to the program.

of Implementing Documents, notes that procedures STA-737 and STI-737.01 have actions to revise them to include several aspects Discuss why the identified changes to the associated with license renewal with implementing schedules implementing procedures are not considered associated with the PEO. enhancements to the program.

Comanche Peak Nuclear Power Plant, Units 1 and 2 License Renewal Application (LRA) Breakout Audit Questions LRA Section B.2.3.2 Water Chemistry Question LRA/SLRA LRA/SLRA Background / Issue Discussion Question / Request Number Section Page (As applicable/needed) 1 N/A N/A The 2020 primary water self-assessment, TR-2020- Please clarify how the TR-2020-004330 self-004330, identifies improvement opportunities. Section assessment results were incorporated into the 4.10.2 of the Water Chemistry AMP basis document, implementing documents.

LUM00020-REP-040, states that results of the TR-2020-004330 self-assessment were incorporated into procedures. However, Revision 15 of CHM-120, Primary Chemistry, the revision referenced in the AMP basis document, is dated 2012.

2 B.2.3.2 B-34 The Industry OE section refers to NRC Information Please describe the strategy at CPNPP for Notice (IN) 2007-37 regarding accumulation of assessing and limiting the accumulation of deposits in steam generators and the potential effect deposits at TSPs that could affect tube on tube integrity. The LRA states that CPNPP integrity.

performs sludge lancing to remove deposits on the secondary side of SGs.

Although sludge lancing is a commonly used method of deposit removal, it is used in the tubesheet region. IN 2007-37 addressed deposits in the tubesheet region as well as openings in broached tube support plate (TSP) openings. This example of operating experience in the LRA does not address deposits at TSPs. The operating experience described in IN 2007-37 was related to deposits in broached quatrefoil-shaped TSP openings. Steam generators at CPNPP have

broached quatrefoil (Unit 2) and trifoil (Unit 1) TSP openings.

3 N/A N/A Section 8 of Primary Chemistry Strategic Plan, a) Please clarify whether the term, EPRI identifies differences between practices at CPNPP and Primary Water Chemistry Guidelines suggest practices that the EPRI primary water chemistry , in Section 8 of Primary Chemistry guidelines (GL) suggest. The document references Strategic Plan, refers to recommended Revision 7 of the GL in Section 9 (References), but elements in the EPRI GL.

Section 8 has descriptions of information that matches Revision 6 of the GL rather than Revision 7, such as b) Please discuss whether the differences Table 3-4. As a result, the differences between CPNPP between CPNPP practices and Revision 7 of and the EPRI GL referenced in the LRA are not clear to the EPRI GL are limited to recommended the staff. elements and do not include mandatory or shall elements. Primary Chemistry Strategic In addition, the meaning of EPRI GL suggestions is Plan refers to both Revisions 6 and 7 of the unclear. The staffs understanding is that in this context EPRI GL, but the LRA proposes an exception to the word suggest in Primary Chemistry Strategic use Rev. 7.

Plan refers to recommended elements in the EPRI GL.

4 N/A N/A TR-2019-004928 describes a possible departure from a) Please clarify the circumstances regarding EPRI PWR Secondary Water Chemistry GL with the possible departure from EPRI guidelines respect to the time to establish wet layup chemistry in and the conclusions from the evaluation of the Unit 1 SGs in 1RF20. The TR description indicates corrosion and other effects.

the seven-day requirement in the GL was met, but the TR also includes a corrosion estimate for 13.73 days. b) Please describe the moisture separator manufacturing deviations and feedring repairs, The TR also refers to SG moisture separator and discuss any effects on the present manufacturing deviations, feedring repairs, and foreign management of loose parts and foreign objects objects in the Unit 1 feedwater rings, feedwater in the Unit 1 SGs.

nozzles, and lower deck plates.

5 N/A N/A Attachment 8.G of CHM-130, , has a figure Please clarify the calculation of the useable depicting the steam generator high head chemical feed portion of the tank since it appears to include a tank with dimensions and formulae for volume cylindrical portion of the tank defined as non-calculations. The figure shows a portion of the usable.

cylindrical section of the tank identified as non-usable. However, this same section of the tank

appears to be included in the calculation of usable volume, Vu, since Vu is based on the full height of the cylindrical portion (Vc).

Comanche Peak Nuclear Power Plant, Units 1 and 2 License Renewal Application (LRA) Breakout Audit Questions LRA Sections B.2.3.10 and 4.7.7 Steam Generators and TLAA SG Tubes Metal Corrosion Allowance Question LRA/SLRA LRA/SLRA Background / Issue Discussion Question / Request Number Section Page (As applicable/needed) 1 B.2.3.10 B-77 to B- The LRA states that the Steam Generators AMP is Please discuss the use of the EPRI IAGL 80 consistent, with three exceptions, with the NUREG-1801 in the AMP and other steam generator Section XI.M19, as modified by LR-ISG-2016- program documents, and how consistency

01. However, as currently proposed, with exceptions, the is being established and maintained for the Steam Generators program is not fully consistent with the referenced EPRI guidelines among all of XI.M19 (as modified by the ISG). the Comanche Peak implementing documents.

The staff notes the following:

  • The EPRI IAGL is mentioned on LRA p. B-79, but there is no statement referencing a report number or revision number. NUREG-1801 Section XI.M19, as modified by LR-ISG-2016-01, references Revision 4 of the IAGL (EPRI 3002007571) in Element 3 (Parameters Monitored/Inspected) and Element 6 (Acceptance Criteria). The latest revision of the IAGL (Revision 5 in 2021) could be referenced using an exception to Element 6.
  • Revision 4 of the EPRI IAGL is also referenced in implementing document STA-733, Steam Generator Reliability Program. The staff did not

determine if this is the only implementing document that may need to have references to guideline documents updated.

2 B.2.3.10 B-78 In LR Section B.2.3.10, the stated inspection intervals for Please discuss the intended inspection the steam generator divider plates, channel heads, intervals for the SG divider plates, channel tubesheets, and tube-to-tubesheet welds are consistent heads, tubesheets, and tube-to-tubesheet with NUREG-1801 Section XI.M19, as modified by LR-ISG- welds, and consistency among the Steam 2016-01. However, those intervals are not consistent with Generators program documents.

the current CPNPP technical specifications, as approved in License Amendment 182 (ML21321A349). Specifically, o The LRA states that visual inspections are performed at least 72 effective full power months (EFPM) or every third refueling outage for Unit 1, and 48 EFPM or every other refueling outage for Unit 2.

o In the technical specifications approved in Amendment 182, visual inspections are performed at least every 96 EFPM for Unit 1, and at least every 54 EFPM for Unit 2 (with additional provisions for enhanced probe inspections).

In addition, the inspection intervals stated in Section B.2.3.10 of the LRA are not consistent with the intervals stated in Section 4.3.2 of the AMP basis document, LUM00020-REPT-047.

3 B.2.3.10 B-79 to B- LRA Section B.2.3.10, Steam Generators, refers to tube Please discuss the reason for referencing 85 repairs and tube sleeves. References to repairs and tube repairs and sleeves given they sleeves are also found in implementing documents for the currently are not approved methods for Steam Generator Program. However, Comanche Peak addressing tube degradation.

Units 1 and 2 do not have sleeving or other tube repair methods approved in the technical specifications.

4 Table 3.1.2-4 3.1-134 LRA Table 3.1.2-4, Steam Generators - Summary of Aging Please discuss how an internal Management Evaluation, identifies components such as environment is defined for steam generator 3.1-147 divider plates, tubesheets, tube-to-tubesheet welds, and components such as divider plates, 3.1-148 tube support plates as having a Reactor coolant (internal) tubesheets, tube-to-tubesheet welds, and environment. Because these are solid components with tube support plates.

only exterior surfaces, it is unclear to the staff why an internal environment is identified.

5 3.1.2.2.11.2 3.1-16 LR-ISG-2016-01, Appendix D, contains revised guidance Please clarify the statement that the Unit 1 for NUREG-1800 (SRP-LR), Revision 2, for managing tube-to-tubesheet welds are Alloy 690 primary water stress corrosion cracking (PWSCC) of steam material. The staff is seeking clarification generator divider plate assemblies and tube-to-tubesheet of how the welds conform to the welds. With respect to tube-to-tubesheet welds, the acceptance criteria in LRA Section acceptance criteria for Section 3.1.2.2.11.2 for units with 3.1.2.2.11.2, which are stated in terms of thermally treated Alloy 690 steam generator tubes depends the tubesheet cladding material.

on the tubesheet material. The guidance states that for units with thermally treated Alloy 690 tubes and Alloy 600 type tubesheet cladding, a plant-specific AMP is necessary unless certain conditions are met, such as a 22 percent minimum chromium content of the tube-to-tubesheet welds). For units with Alloy 690 tubes and tubesheet cladding material, a plant-specific AMP is not necessary.

Section 3.1.2.2.11.2 of the SLRA states that the Unit 1 steam generator divider plate assemblies, tubes, and tube-to-tubesheet welds are Alloy 690 material and credits the Water Chemistry and Steam Generators AMPs for managing PWSCC. However, because the tubesheet cladding material is not identified, and the conditions requiring a plant-specific AMP are not addressed, the staff is unable to determine that the acceptance criteria are met for the Unit 1 tube-to-tubesheet welds.

6 N/A N/A CPNPP Procedure NDE-7.10 (Rev. 16, 8/21/2019), Steam Please discuss the reference to SG tube Generator Tube Selection and Examination, Section 4.4.3, examination sampling plans that were Tube Examination Scope and Sampling Plans, has replaced by performance-based technical sampling plan classifications C-1, C-2, and C-3, which is

different than the scope of inspections required in the specifications, including the current current technical specifications. CPNPP technical specifications.

7 N/A N/A CR-2018-002217 states that a qualification matrix was Please discuss the status and trends in developed to identify qualification gaps due to the addressing qualification gaps and high integration of Component Engineering (CE) into the steam generator program turnover.

Systems and Strategic Engineering department. The matrix identified CE positions that need a backup. Resolution for this item describes identifying a previous SG program owner who was an expert but no longer qualified.

CR-2012-000075 includes a recommendation from INPO for improving aspects of program implementation. One item they identified was the high level of program owner turnover.

8 CR-2012-000075 includes a recommendation from INPO Please discuss the relative roles and for improving aspects of program implementation. Item 3f timing of the NDE Level III and program stated that the Vendor NDE Level III used as the utility NDE owner in the inspection planning and oversight representative is not involved early enough review, including the DA, CM, and OA during inspection planning, and that the NDE Level III utility reports.

representative does not sign off on the degradation assessment (DA), condition monitoring (CM) report, or operational assessments (OAs).

Resolution for this item describes how the CPNPP Level III would be more involved in inspection planning and review. The resolution also states, The representative will be reviewing and signing off on the Degradation Assessment, the Condition Monitoring report, and the Operational Assessments.

9 N/A N/A As summarized in ML22020A178, the licensee and NRC Please discuss the results of any staff discussed the fall 2021 steam generator tube corrective actions or other follow-up inspection activities during the inspection. With respect to actions in response to that experience.

the detection of outside diameter stress corrosion cracking at a free span ding, the licensee described how a change

in the eddy current signal had been detected initially in 2008. Subsequent inspections with bobbin probes in 2011, 2014, and 2017 resulted in dispositioning the indication without identifying it as a crack or performing special interest inspections to improve the ability to detect a crack-like signal in the presence of masking signals. During the call, the licensee indicated changes to the inspection program would be considered.

10 B.2.3.10 B-83 The first paragraph for Unit 2 plant-specific Operating Please discuss the difference between the Experience states that six tubes were plugged during the fall 2021 inspection report and the LRA fall 2021 inspection, and that these six tubes were plugged with respect to the causes of tube as a result of previously identified degradation plugging.

mechanisms. However, according to the report from the fall 2021 inspection:

  • Two tubes were plugged on the basis that they are high-stress tubes, and no degradation was identified for these tubes.
  • One tube was plugged due to axial ODSCC at a freespan ding. This degradation mechanism was new to CPNPP, and the report states that is now an existing mechanism based on the fall 2021 inspection.

11 B.2.3.10 B-79 The last full paragraph on page B-79 has the following Please clarify the intended wording for this typographical error: sentence, for example, Installed plugs are routinely inspected and ..

Installed plugged are routinely inspected and .

Other Plant Specific TLAA - SG Tubes Metal Corrosion Allowance 12 4.7.7 4.7.14 This section states: The FSAR Section 5.4.2B.5.4 Please clarify this calculation. Doesnt the Allowable Tube Wall Thinning Under Accident Conditions, assumed corrosion rate, equivalent to which covers Unit 2, contains the following discussion of 0.080 mils thinning leave a conservative the corrosion of steam generator tubing:

The corrosion rate is based on a conservative weight loss 2.9 mils for general corrosion? (i.e., 3 mils rate for mill annealed Inconel tubing in flowing 650°F - 0.080 mils = 2.92 mils) primary side reactor coolant fluid. The weight loss, when equated to a thinning rate and projected over a 40-yr plant life with appropriate reduction after initial hours, is equivalent to 0.080 mils thinning. The assumed corrosion rate of 3 mils leaves a conservative 2.2 mils for general corrosion thinning on the secondary side.

13 3.1.2.2.11.1 3.1-13-3.1- LRA Section 3.1.2.2.11.1 states that the evaluation For Question 10 in LTR-CECO-21-081, 14 determined the 2014 EPRI report TR-3002002850 is please step through the analysis that applicable and bounding for CPNPP Unit 2 SGs. Based on demonstrates how EPRI report TR-LR-ISG-2016-01, this determination makes it unnecessary 3002002850 is applicable and bounding for to have a plant-specific AMP for verifying the effectiveness the CPNPP Unit 2 SGs.

of the Water Chemistry and Steam Generators AMPs.

However, the determination that the 2014 EPRI report is bounding, as documented in Westinghouse LTR-CECO 081 P/NP Rev. 1, Question 10, states that the loads used in the 2014 EPRI report do not strictly bound the design and transient loads for CPNPP Unit 2. The limiting differential was then used to calculate tubesheet vertical displacements and compare them to the vertical displacements calculated for the limiting SG model in a 2007 EPRI report. The conclusion that the EPRI report is bounding for CPNPP Unit 2 despite the increased pressure differentials, appears to be based largely on the comparison of these vertical displacement calculations.

It is unclear to the staff how LTR-CECO-21-081 demonstrates CPNPP Unit 2 is bounded by the 2014 EPRI report. For example:

  • It is not clear why vertical displacement is considered sufficient to determine whether the CP2 SGs are bounded by the 2014 EPRI report.
  • Section 4 of the 2014 EPRI report evaluated two cracking scenarios representing limiting cases: cracks propagating from the divider plate assembly into the channel head low alloy steel due to fatigue, and cracks propagating through the tube-to-tubesheet welds. The evaluation for crack propagation into the channel head low alloy steel was based on internal pressure loading, multiple thermal transients for the hot leg and cold leg, finite element stress analysis, and fatigue crack growth analysis. The conclusion that structural integrity of the channel head is not compromised based on a crack in the divider plate was based on the fatigue crack growth analysis.

14 N/A N/A TR-2019-004928 describes a possible departure from EPRI a) Please clarify the circumstances (Also PWR Secondary Water Chemistry GL with respect to the regarding the possible departure from submitted time to establish wet layup chemistry in the Unit 1 SGs in EPRI guidelines and the conclusions from as Water 1RF20. The TR description indicates the seven-day the evaluation of corrosion and other Chemistry requirement in the GL was met, but the TR also includes a effects.

Question corrosion estimate for 13.73 days.

4) b) Please describe the moisture separator The TR also refers to SG moisture separator manufacturing manufacturing deviations and feedring deviations, feedring repairs, and foreign objects in the Unit repairs and discuss any effects on the 1 feedwater rings, feedwater nozzles, and lower deck present management of loose parts and plates. foreign objects in the Unit 1 SGs.

Comanche Peak Nuclear Power Plant, Units 1 and 2 License Renewal Application (LRA) Breakout Audit Questions LRA Structural Scoping and Screening Question LRA/SLRA LRA/SLRA Background / Issue Discussion Question / Request Number Section Page (As applicable/needed) 1 LRA Table 2.2-7 LR DWG LR-STRUCT-01 shows the SW Discharge Please provide a justification for the canal not Canal as in-scope for LR; however, LRA Table 2.2-3 being in scope of LR or identify how the canal 2.2-3 indicates the canal is not in-scope for LR. is age-managed.

2 LRA 2.4.8 2.4-23 Per LRA Section 2.4.8 (pdf pg. 279) Traveling screens Explain how the screen portion of the traveling perform their function with moving parts, are active and screens will be age-managed or why age-are not subject to AMR. The staff agrees the overall management is unnecessary.

traveling screen component is active; however, it is unclear why the actual screen portion of the traveling screen is considered active and how it will be age-managed.

Comanche Peak Nuclear Power Plant, Units 1 and 2 License Renewal Application (LRA) Breakout Audit Questions LRA Section B.2.3.9, Bolting integrity Question LRA/SLRA LRA/SLRA Background / Issue Discussion Question / Request Number Section Page (As applicable/needed) 1 Bolting Basis doc NUREG-1801 XI.M18, element 3, notes that this Please identify specific sections in implementing Integrity pg. 16 of 42 AMP monitors bolting for the effects of aging, procedures that explain how the appropriate Basis including leakage, loss of material, cracking, and inspections are conducted for this AMP.

Document, loss of preload/loss of prestress. Element 4 notes Sections 4.3 that periodic inspections are conducted for signs of If this level of detail does not exist in current plant and 4.4 leakage to ensure age-related degradation is documents, please explain why an enhancement detected. is not necessary for this element.

NUREG-2191 also notes that site procedures should include inspection parameters, such as lighting, distance, etc., to ensure an adequate inspection is performed.

The AMP basis document notes that these aging effects are monitored by the AMP and references several documents (9.12, 9.62 - 9.65).

The staff reviewed these documents; however, it was unclear how these documents captured clear guidance on how to actually implement the program and the appropriate inspections.

Reference 9.65 provides general guidance on what should be reviewed during a walkdown, including a sample walkdown checklist; however, there is no clear guidance on how to conduct inspections.

2 Bolting Basis doc NUREG-1801 XI.M18, element 6, notes that for Please identify site documents that clearly define Integrity pg. 20 of 42 non-ASME pressure retaining bolting, indications of indications of aging for bolted connections. If this Basis aging should be dispositioned in accordance with level of detail does not exist in current plant

Document, the corrective action process (CAP). NUREG-2191 documents, please explain why an enhancement Section 4.6 states that leaking joints do not meet acceptance is not necessary for this element.

criteria.

The AMP basis document notes that indications of aging are dispositioned in accordance with the CAP and references Ref. 9.65.

As noted above, Ref 9.65 provides general guidance on what should be reviewed during a walkdown but does not provide clear guidance on what would be considered indications of aging.

3 LRA Tables LRA pg. 3.3- Several items in the LRA identify loss of preload for Please explain why a note H is referenced for 3.3.2-2, -6, - 139, 187, carbon or stainless-steel materials in a these items and why no GALL item is referenced.

12 279, 280 condensation or wastewater environment and reference generic Note H, which indicates the aging effect is not in GALL for this component, 3.3-32 material, and environment.

LRA Table LRA Table 3.3-1, item 15 notes that the bolting 3.3-1 integrity AMP manages loss of preload for steel and stainless-steel bolting.

It is unclear to the staff why the LRA credits a note H for these items, instead of referencing Table 3.3-1, item 15.

4 Bolting Basis doc NUREG-1801 XI.M18, element 2, notes that Please clarify whether any high strength bolts with Integrity pg. 15 of 42 preventive measures include using bolting material actual yield strength of 150 ksi or greater are Basis that has an actual measured yield strength limited currently used as closure bolting.

Document, to less than 1,034 MPa (150 ksi).

Section 4.2 If high strength bolts have been used, discuss The AMP basis document Section 4.2 states that procedures to identify these high strength bolts high strength bolts with actual yield strength of 150 and explain how they will be age managed.

ksi or greater are not used as closure bolting for pressure retaining components.

LRA Section B.2.3.9 notes that procedures will be enhanced to minimize any future use of bolting material with an actual yield strength greater than or equal to 150 ksi in portions of systems within the scope of the Bolting Integrity program.

It is unclear to the staff whether high strength bolts with actual yield strength of 150 ksi or greater exist in the plant currently.

5 Bolting Basis doc NUREG-1801 XI.M18, Element 3, notes that this If future use is to be minimized, as opposed to Integrity pg. 16 of 42 AMP should monitor cracking for high strength prohibited, please discuss the need to enhance Basis closure bolting if used. CPNPP Element 3 to include monitoring for Document, cracking of high-strength closure bolts.

Section 4.3 The AMP basis document Section 4.3 states that high strength bolts with actual yield strength of 150 ksi or greater are not used as closure bolting for pressure retaining components.

CPNPP Element 3 does not include procedures to monitor cracking for high strength closure bolting.

The information in CPNPP Element 3 appears to be inconsistent with the information in CPNPP Element 2 CPNPP regarding minimizing future use of high strength closure bolts.

Comanche Peak Nuclear Power Plant, Units 1 and 2 License Renewal Application (LRA) Breakout Audit Questions LRA Sections:

AMP B.2.3.13 Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems TLAA 4.7.4 Crane Load Cycle Limits AMP: 24 and TLAA: 116.4 Question LRA LRA Page Background / Issue Discussion Question / Request Number Section (As applicable/needed) 1 AMP Page B-96, Basis Document Reports, LUM00020-REPT-050, Rev. Discuss why Drumming Storage Area B.2.3.13, 1, (AMP for Inspection of Load Handling Systems) and Crane, is listed in Table 4.7.2-2 (TLAA) and Page 4.7-6, LUM00020-REPT-083, Rev. 3, (TLAA for Cranes) in Table 17A-1 of the FSAR but was TLAA provided the lists of load handling systems, in Section excluded from the scope of AMP in Section 4.7.4, FSAR Table 17A-1 4.1 and in Table 4.7.2-2 that are in scope for the LR 4.1 of the Basis Document Reports, Basis (AMP/TLAA), respectively. LUM00020-REPT-050, Rev. 1, and Document and consequently, in Section B.2.3.13 of the As stated in Section B.2.3.13 of the LRA, Table 17A-1 LRA.

Reports, Table 1-2 of in FSAR was reviewed to identify the cranes that are FSAR, Report designed in accordance with CMAA-70, 1975, or considered equivalent to CMAA-70.

and Report DBD-ME- Report DBD-ME-006, Rev. 40, also identified Drum 006, Rev. Storage Area Crane (CPX-MESCDS-01), in Table 1-2 40 as it does not require additional review and evaluation.

2 AMP Page B-96, Basis Document Reports LUM00020-REPT-050, Rev. Discuss why some of the load handling B.2.3.13, 1, (AMP for Inspection of Load Handling Systems) and systems, listed in Section 4.1 of the Basis Page 4.7-6, LUM00020-REPT-083, Rev. 3, (TLAA for Cranes) Document Report, LUM00020-REPT-050, TLAA 4.7.4, provided twenty-five (25) in Section 4.1 and twelve (12) Rev. 1, were excluded from the scope in of and in Table 4.7.2-2 load handling systems, that are in the Basis Document Report, LUM00020-Basis scope for the LR (AMP/TLAA), respectively. REPT-083, Rev. 3, (TLAA for Cranes).

Document 2. Furthermore, Report DBD-ME-006, Rev. 40, in 2. Discuss why all the overhead load Reports, Table 1-1 identified over twenty-eight (28) handling systems, identified in Table

and Report overhead load handling systems, with potential 1-1 in Report DBD-ME-006, Rev. 40, DBD-ME- for heavy loads drop on or near spent fuel or were not considered in the scope of 006, Rev. systems required for plant shutdown or decay AMP/TLAA.

40 heat removal.

Note: The following overhead load handling systems, in Table 1-1 of the report DBD-ME-006, Rev. 40, were not considered in the scope of AMP/TLAA:

1.b - Overhead Crane 130Ton Hook Critical Lifting Devises 26 - Mobile Crane 27.b - VCT Special Lifting Devises 3 OE List in Excel File: In the electronic portal, the applicant provided a table Describe why some of the load handling portal XI.M23.xlsx (file XI.M23.xlsx) listing information related to OEs on systems (XI.M23), listed in OEs (file the load handling systems (XI.M23),. Based on the XI.M23.xlsx) were not in the scope of AMP/

cursory check of the OEs against the Basis Reports TLAA as identified under Examples, in the (AMP/TLAA) - as listed below, the staff identified the adjacent column.

load handling systems, that were not considered in the scope of AMP/TLAA.

Examples:

1. CR-2014-001643: The Galion Mobile Crane -

XI.M23, related to refueling.

2. CR-2012-012795: CPX-MEMHMB-02, Main Shop Electric Hoist - XI.M23, related to refueling.
3. CR2015-003675/CR2015-003194/CR2016-006515/TR-2016-001599/CR-2015-010930:

CPX-MESCCW-01, Circulating Water Intake Structure Gantry Crane X XI.M23, related to refueling.

4. TR-2016-005487/TR2018-001820: TCX-FHSCMC-01, Fuel Handling Refueling Manipulator Crane 2 XI.M23, related to refueling.
5. TR-2018005800: Galion Crane, 150 Crane 15T -

XI.M23 - related to refueling.

6. TR-2018-005799: E0249-20 Ton Glove Crane -

related to refueling.

7. CR-2018-005660: TBX-FHSCFB-01, Fuel Handling Refueling Manipulator Crane 1 XI.M23, related to refueling.

4 TLAA 4.7.4, Page 4.7-6 Basis Document Report, LUM00020-REPT-083, Rev. 3, It is not clear why two (2) out of three (3) and (TLAA for Cranes), provides a Project Report options were chosen!

Preparation Checklist, that the Item 3 asking Have the Basis appropriate review forms/checklists been completed? In Document response, both, Yes, and N/A were checked.

Report Note: This issue may be editorial!

5 TLAA 4.7.4, Page 4.7-6 In Section 7.1, LRA Section 4.7.2, of Basis Document Refer to the appropriate section of 4.7.4, and Report, LUM00020-REPT-083, Rev. 3, (TLAA for from LRA in Basis Document Report, Cranes), refers to Section 4.7.2 for TLAA in the LRA. LUM00020-REPT-083, Rev. 3, (TLAA for Basis However, it is Section 4.7.4 in the LRA. Cranes),

Document Report Note: Editorial.

6 OE List in Excel File: In the electronic portal, the applicant provided a table Elaborate identified specific issues related portal XI.M23.xlsx (file XI.M23.xlsx) listing information related to OEs on to the cranes that are not considered in the load handling systems (XI.M23), The trending optimal conditions.

report, TR-2021-006651, describes: This IR is to track an STA-748 equipment reliability task team effort on CPNNP cranes. The health of the cranes so far in 2rf19 has not been optimal.

XI.M23, related to refueling.

7 AMP Page B-97, Forth bullet, the paragraph starts with In November of Confirm whether the Refueling Machine B.2.3.13, 2018, during the inspection of the Refueling Machine crane hoist, is in the scope for AMP/TLAA.

Under crane hoist...

is the crane ID #: TBX-FHSCFB-01?

Operating It is not clear whether the Refueling Machine crane Experience, hoist, is in the scope for AMP/TLAA. [CR-2018-and Plant- 005660]

Specific OE, Note: CR-2018-005660 was also identified above in Forth bullet Question 3, Item 7.

8 Procedure Page 3 On page 3 of Procedure MDA-402-13, states Update Discuss why Step 6.1.2.3 on page 12 in TPMDA- Step 6.1.2.3 for load testing overhead hoists based on Procedure MDA-402-13 was not updated.

MDA-402- Effected page latest edition of ASME B30.16.

13 12 The Step 6.1.2.3 on page 12 in Procedure MDA-402-13 Page 12, Item appears to be not updated as stated on page 3 above.

6.1.2.3 Note: In Section 4.7, Corrective Actions, of the Basis Document Reports, LUM00020-REPT-050, Rev. 1, refers to reference 9.24 MDA-402, Rev. 13, Control of Load Handling Equipment, for the implementation of ASME B30.16. Furthermore, in AMP B.2.3.13 of the LRA, Element 3, Parameters Monitored or Inspected, and Element 6, Acceptance Criteria, will be enhanced to include ASME B30.16.

9 N/A N/A It is not clear whether CPNPP, Units 1 and 2, has any Clarify whether CPNPP, Units 1 and 2, has monorails and underhung cranes, at the site. any monorails and underhung cranes, at the site that can be considered in the APM/TLAA of LRA.

Comanche Peak Nuclear Power Plant, Units 1 and 2 License Renewal Application (LRA) Breakout Audit Questions LRA Section B.2.3.29 AMP: ASME Section XI, Subsection IWE Question SLRA SLRA Background / Issue Discussion Question / Request Number Section Page (As applicable/needed) 1 3.5.2.2.1.3.1, 3.5-21, The further evaluation in the referenced LRA section a) Explain and reconcile the noted potential states in part: inconsistency in the referenced LRA B.2.3.29, B-173, description and the scope of program An evaluation of the acceptability of inaccessible areas element of GALL-SLR AMP XI.S1 with regard A.2.2.29 A-24 is required when conditions exist in augmented to addressing acceptability of inaccessible areas that could indicate degradation could also exist areas.

or could have extended into the inaccessible areas.

Inaccessible areas are not necessarily always located adjacent to locations that are or may be identified for augmented examination. LRA Section B.2.3.29 claims the LRA IWE program with enhancements will be consistent with the GALL-LR program XI.S1. The LRA statement cited in the 1st paragraph above appears to be inconsistent with corresponding statements in LRA B.2.3.29, A.2.2.29 and the scope of program element of GALL-LR AMP XI.S1, which states the following with regard to managing aging effects in inaccessible areas:

the licensee is to evaluate the acceptability of inaccessible areas when conditions exist in accessible areas that could indicate the presence of or result in degradation in inaccessible areas.

2 B.2.3.29 & B-174 & To establish consistency with the GALL-LR Report AMP a) Discuss potential revised language to the Table A-3, Item A-79 XI.S1, the LRA AMP includes the following enhancement and related LR commitment 31(a) enhancement to the preventive actions program that provides specific clarity of actions and element: objective in a manner that demonstrates consistency with the preventive actions Reconcile the preventive actions in NUREG-1339, program element of the GALL-LR AMP EPRI NP-5769, and EPRI TR 10423 with the existing XI.S1.

procedures and practices for structural bolting.

The preventive actions program element of the GALL-LR AMP XI.S1 states, in part: The program is also augmented to require that the selection of bolting material installation torque or tension and the use of lubricants and sealants are in accordance with the guidelines of EPRI NP-5769, EPRI TR-104213, and the additional recommendations of NUREG-1339 to prevent or mitigate degradation and failure of structural bolting.

  • The language of the enhancement and related LR commitment appear to be very general and non-specific, lacks clarity with regard to the specific objective of the enhancement, and it is unclear how it would make the program element consistent with the GALL-SLR.

3 B.2.3.29 & B-174 & In consideration of operating experience and laboratory a. Confirm or clarify whether or not Table A-3, Item A-79 examinations that show that the use of molybdenum MoS2 or other lubricants containing 31(b) disulfide (MoS2) and other products containing sulfur as sulfur have been or will be used prior a lubricant is a potential contributor to stress corrosion to the PEO for high strength bolting cracking (SCC) especially in high-strength bolting, the (actual tensile strength greater than LRA includes the following enhancement to the 150 ksi) within the scope of the LRA preventive actions program element: Prohibit the use B.2.3.29 (IWE) AMP.

of molybdenum disulfide or other sulfur containing lubricants for structural bolts. b. If used in response to a), discuss how the potential for SCC in such bolting

  • It is not clear if MoS2 or other lubricants will be adequately managed during containing sulfur have been or will used in the PEO as required by 10 CFR

structural bolting in the scope of the LRA AMP 54.21(a)(3). Also, discuss related prior to entering the period of extended changes that will be made to the LRA operation (PEO). If so, it is not clear how the AMP.

potential for SCC in such bolting be adequately managed during the PEO.

4 B.2.3.29 B-173 Section 4.3.2 on page 16 of PBD (LUM00020-REPT- 1. Discuss and justify how the LRA AMP

& B- 066, Rev 1) for AMP Element 3 (Parameters Monitored program element 3 is consistent with 174 or Inspected) states under Category E-C: The the GALL-SLR AMP regarding Containment Areas Visible Surfaces (Item E4.11) will be Examination Category E-C.

inspected using the general visual examination method to examine the parts defined during the third interval 2. If determined to be inconsistent, based on IWE-1241 requirement and Category E-A discuss what revision will be made to examinations. the program element 3 in the PBD to be consistent with GALL-LR as

  • Contrary to the claim that program element 3 of claimed, or justify the exception to the the LRA AMP is consistent without exception to GALL-LR AMP XI.S1.

GALL-SLR AMP XI.S1, the examination method specified for Examination Category E-C (Item 4.11) in Table IWE-2500-1 is VT-1 method, and not general visual examination method cited above, and therefore, inconsistent or taking exception with the ASME Code Section XI, Subsection IWE and GALL-LR AMP XI.S1.

5 B.2.3.29 & B-173 & PBD (LUM00020-REPT-066, Rev 1), Section 4.4.2, a. Discuss how the Detection of Aging PBD Section PBD states on page 18: The frequency of the examinations Effects program element of the LRA 4.4.2 page 18 on the structural components is specified in the 2007 AMP described in the PBD is edition through 2008 addenda of ASME Section XI, consistent with GALL-LR AMP XI.S1, Subsections IWE as claimed, when the code edition

[Ref. 9.20, Table IWE-2500-1]. used during the PEO will not be the 2007 Edition with 2008 addenda. Also,

  • Contrary to the above statement in the PBD, the discuss the changes that may need to GALL-LR AMP XI.S1 requires the examination be made to the PBD to achieve methods, frequency and scope to be consistent consistency.

with the code edition(s) during the PEO in accordance with 10 CFR 50.55a, and is therefore inconsistent with the GALL-LRA AMP

XI.S1. There is no mention of 10 CFR 50.55a in Section 4.4.2 of the PBD.

6 B.2.3.29 & B-174, To establish consistency with the GALL-LR Report AMP a. Clearly state in the enhancement and Table A-3, Item A-79, A- XI.S1, the LRA AMP includes the following the related LR commitment the 31(c), 24 enhancement to the detection of aging effects program frequency at which the proposed element: Monitor cracking due to cyclic loading of non- supplemental surface examinations to A.2.2.29 piping penetrations and DMWs between the stainless detect cracking will be performed.

steel piping and the steel sleeve/forging by periodic Also, justify the sufficiency of the supplemental surface examinations consistent with examination frequency to provide the frequency of this AMP and the 10 CFR Part 50, adequate management of the aging Appendix J AMP. effect.

  • Since the surface examinations are b. State the specific non-piping supplemental to the routine examinations penetrations that are subject to required by Subsection IWE and intended to be periodic supplemental surface plant-specific, the GALL-LR AMP does not examinations by this enhancement.

specify the interval for these examinations. Also, state the specific supplemental examinations methods (e.g., MT, PT,

  • The LRA does not explicitly state what specific E-VT1 etc.) capable of detecting non-piping penetrations are included in this cracking that will be used.

enhancement, and the specific supplemental examination methods that will be used and its c. Clarify why the frequency of the capability to detect cracking. proposed supplemental examination is related to 10 CFR 50 Appendix J AMP

  • It is not clear how the supplemental surface cited in the enhancement. If Appendix examinations are related to the 10 CFR 50, J tests will be credited to detect Appendix J AMP which is a performance cracking due to cyclic loading for monitoring program, whereas the IWE program certain components, identify these is a condition monitoring program. components and the type of Appendix J test capable of detecting crack that will be used, including the frequency of the test.
d. Discuss conforming changes, if any, that may need to be made to the LRA

AMP and/or its FSAR supplement, consistent with the above requests.

7 B.2.3.29 & B-174 & The detection of aging effects program element a. Clearly state in the enhancement the Table A-3, Item A-79 includes an enhancement of a pre-PEO supplemental method(s) capable of detecting 31(d) one-time inspection, using methods capable of cracking that will be for the one-time detecting cracking, of a representative sample (4 inspection.

penetrations and 1 transfer tube) to confirm the absence of SCC. b. Discuss the adequacy of the proposed representative sample discussing the

  • The enhancement does not state the method(s) total number of the population of capable of detecting cracking that will used for penetrations/DMWs it represents.

the inspection.

c. Discuss and include in the
  • There is no information provided of the enhancement or as a separate adequacy of the representative sample, enhancement what additional actions especially considering the population of SS (e.g., sample expansion, periodic penetrations or DMWs associated with high examination with method and temperature piping it represents. frequency, etc) will be taken if absence of SCC is not confirmed or if
  • The enhancement does not address what SCC is detected.

additional actions will be taken if the absence of SCC is not confirmed or if SCC is detected from d. Clarify and reconcile if there are the one-time examination. common components that are subjected to the actions in both LR Commitments 31(c) and 31(d) discussed in Questions 6 and 7 above.

8 B.2.3.29 B-175 The first bullet under Plant-Specific OE states, in part: a. Clarify and correct the cited

. There is no documented evidence of degraded inconsistent statements in the plant-conditions like bulges in the liner plate, etc.; specific operating experience Contrary to the above statement, the second full bullet description.

on LRA page B-175 beginning with NRC IN 97-10, states, in part: A bulge to the Unit 1 liner was b. Clarify if there is physical evidence of documented and evaluated. age-related degraded conditions (e.g.,

corrosion, moisture barrier degradations, etc) of significance in

the containment liner or other containment pressure-retaining boundary components in the scope of the LRA AMP for Comanche Peak Units 1 and 2.

9 B.2.3.29 B-175 The conclusion paragraph under the discussion of c. Clarify and correct, if needed, how the Industry OE states on LRA page B-175: . These referenced conclusion statement examples provide objective evidence to confirm that under Industry OE in LRA Section station testing procedures are effective to maintain B.2.3.29 is supported by the industry containment integrity. It is not clear why the statement OE discussed above the statement refers to station testing procedures when the industry specifically with regard to the OE discussed or evaluated therein relate to findings of reference to station testing degradation identified as part of the containment ISI procedures.

program, which is essentially a condition monitoring program and not a testing or performance monitoring program.

10 B.2.3.29 B-175 The LRA plant-specific OE description for the LRA AMP a. Confirm or clarify if the plant-specific includes only a single factual plant-specific OE OE of a loose bolt is the only and example, which is of a loose bolt found in 2011 on the most significant plant-specific OE of handwheel gear box of the Unit 2 Personnel aging degradation of the containment Emergency Air Lock. Based on this, the LRA concludes pressure-retaining boundary that: The above OE provides objective evidence that components within the scope of the the ASME Section XI, Subsection IWE AMP has been LRA IWE AMP. If not describe other and will continue to be effective in ensuring that significant OE that would provide component intended functions are maintained objective evidence in support the LRA consistent with the CLB through the PEO. conclusion.

  • The factual description of plant-specific OE b. Are there components or surfaces provided in the LRA appears to not adequately identified for augmented examination support the stated conclusion that it provides under the CISI (IWE) program in the objective evidence of the effectiveness of the past or currently. If so, describe the AMP in adequately managing aging effects such areas and conditions based on which that intended functions are maintained through they were identified for augmented the PEO. examination.
  • In support of its OE conclusion, the LRA does c. Confirm whether the containment not provide explicit supporting statement(s) of pressure-retaining boundary the physical material condition of the components under the scope of the containment pressure-retaining boundary LRA AMP have had no plant-specific components within the scope of the AMP aging degradations (e.g., corrosion, observed based on condition monitoring through moisture barrier degradations etc.) of the containment inservice inspection program significance at Comanche Peak Units and the maintenance rule program. 1 and 2.
  • Section 3.7 Augmented Examinations of the d. Discuss the physical material Interval 4 CISI Program Plan - Section XI on condition of the containment pressure-the ePortal, states, in part: .... Areas previously retaining boundary components under identified by the CPNPP Coatings Program as the scope of the LRA AMP based on areas/items of specific interest are also condition monitoring inspections considered to require special performed under the CISI (IWE) and attention for CISI examination. These areas will maintenance rule programs. If be further assessed during the fourth supported, provide supplemental interval of examinations and may be designated statement(s) based on the observed as augmented areas by the CISI Program material condition that would support Plan. the stated LRA OE conclusion.

11 B.2.3.29 B-173 LRA Section B.2.3.39 states on page B-173: Final a. Clarify the referenced discrepancy Reports are generated for engineering evaluations in between LRA Section B.2.3.29 and accordance with Code Case N-532-4. This is also the CPNPP CISI Program Plans with reflected in the PBD on the ePortal. regard to use of stated code case N-532-4.

  • However, Appendix B of the CPNPP Containment ISI Program Plan provided on the b. Clarify if the referenced code case or ePortal for both the 3rd as well as 4th CISI any other Section XI code cases will Intervals state: No [Section XI] Code Cases be adopted for the LRA AMP for the Have Been Adopted by CPNPP. PEO, and if so clarify how the appropriate revision to be used will be
  • The most recent revision of this code case determined.

incorporated by reference in 50.55a via RG 1.147 is N-532-5 dated 1/4/2011. If adopted, 10 CFR 50.55a(b)(5) requires the latest revision of

code cases incorporated by reference therein to be used in subsequent inspection intervals.

12 Interval 4 CISI CISI

  • 4th Interval CISI Plan document on the ePortal, a. Briefly discuss the areas indicated as Program Plan Plan Section 3.6 Accessible/Inaccessible Areas inaccessible on the referenced CISI on ePortal: pages 3- states, in part: Inaccessible areas are exempt Plan drawings on pdf pages 76 & 101, Section 3.6, 10 thru from examination and are shown on CISI and briefly explain why they are 3.12, 3.15, and 3-16; 3- Drawings titled Metal Containment Inaccessible inaccessible.

Tables 3.12-1 24 thru Areas Sh. 1 of 1 in Appendix E

& 3.15-1 3-30 (CPNPP1) and Appendix F (CPNPP2). (For b. Briefly discuss the process used in the drawings, refer pdf pages 76 & 101). It is not field to adequately conduct the clear to the staff what the areas indicated as general visual examinations of the inaccessible on these drawings are and why penetrations, listed in CISI Plan Tables they are inaccessible. 3.12-1 & 3.15-1, with Insulation or Radiant Energy Shielding.

  • 4th Interval CISI Plan document on the ePortal, Tables 3.12-1 (U1) and 3.15-1 (U2) list Containment Penetrations for Examination Category E-A, Item 1.11 general visual examination. The staff notes in the remarks column that some of these penetrations are identified as having Insulation or Radiant Energy Shielding. It is not clear to the staff the process used in the field to adequately conduct the general visual examinations of the penetrations with Insulation or Radiant Energy Shielding.

13 (TRPTable 3.5-1, 3.5-54, The referenced AMR item and FE relates to cracking a. Clarify and justify the non-applicable

77) Item 3.5-1, 052 3.5-34 due to SCC, and loss of material due to pitting and claim for item 3.5-1, 052 in a manner and FE crevice corrosion of stainless steel material that objectively demonstrates that the Section components of Group 7 (concrete with liner) & Group 8 component material and environment 3.5.2.2.2.4 (steel) tanks in a water-standing environment. The required for the aging Table 3.5-1, 052 line item states in the Discussion mechanism/effect(s) does not exist.

column: Not Applicable.

b. Clarify what aging effect(s) in the line It also provides some additional discussion for Group 7 item 3.5-1, 052(cracking due to SCC, tanks and for Group 8 tanks references item 3.3-1, loss of material due to corrosion) is 067and the Fire Water System AMP. Further, LRA applicable and identify the

3.5.2.2.2.4 states, in part: Loss of material due to corresponding Table 2 AMR line items pitting and crevice corrosion in the treated borated that manages the aging effect water..in Group 7 tanks will be managed by the Water Chemistry (B.2.3.2) AMP and One-Time Inspection (B.2.3.19). Cracking due to SCC does not require management as temperatures of the water is less than 140oF.

  • From the descriptions in the LRA, there is lack of clarity regarding the non-applicability claim for item 3.5-1, 052, which aging effect(s) covered by the line item is not applicable, and which aging effect(s) is managed by the referenced AMPs, and which specific corresponding Table 2 AMR items manage the applicable aging effects.

Also, referring to the harsh environment threshold description for SCC in stainless steel on page IX-14 of GALL-LR, Rev. 2, the LRA does not appear to provide discussion on the presence of a harsh environment or operating experience with regard to SCC.

Comanche Peak Nuclear Power Plant, Units 1 and 2 License Renewal Application (LRA) Breakout Audit Questions LRA Section B.2.3.30, ASME Section XI, Subsection IWL AMP Question LRA/SLRA LRA/SLRA Background / Issue Discussion Question / Request Number Section Page (As applicable/needed) 1 A.2.2.30 A-25 The FSAR summary lists types of concrete Explain why these documents are not included degradations but does not identify the appropriate in the FSAR summary.

reference documents (ACI 349.3R).

2 LRA Table 3.5-41 Items 3.5-1, 016 and 024 note that increase in porosity Explain why this aging effect is not inspected 3.5-1, 016 and permeability is not an aging effect requiring for in accessible areas of concrete structures or management because the concrete is not exposed to update the LRA to credit these items and acidic solutions. identify an AMP to manage aging.

Item 3.5-1, 067 notes that the SMP will manage this aging effect for similar concrete.

It is not clear why the aging effects in items 016 and 024 are not applicable. At a minimum, the staff would expect to see an AMP identified to look for these aging effects in accessible areas, even if they are generally not expected to occur.

3 IWE/IWL Pg. 38 The last IWL ISI report (spring 2022) identifies several Please post these documents on the portal for Final Report locations where an area was accepted by evaluation of staff review.

(1RF22) the Responsible Engineer. The report notes that these evaluations are captured in EV-TR-2022-002161-1 and Be prepared to discuss how these evaluations EV-TR-2022-002161-2. meet the acceptance criteria guidance of IWL.

4 TX-ISI-IWL The IWL inspections are implemented by Westinghouse Please verify this document is on the PROP Rev. 8 PROP procedure TX-ISI-IWL. portal or have it added to the portal if it is not already there.

Comanche Peak Nuclear Power Plant, Units 1 and 2 License Renewal Application (LRA) Breakout Audit Questions LRA Section B.2.3.31. ASME Section XI, Subsection IWF Question LRA LRA Background/Issue Discussion Question/Request Number Section Page (As applicable/needed) 1 B.2.3.31 B-180 LRA Section B.2.3.31 provides several enhancements and a Please make available current procedures Table A-3 commitment (Commitment 33) that those enhancements will be for review and further discussion as noted A-80 implemented to the existing ASME Section XI IWF AMP NLT six in Background/Issue.

months prior to entering the PEO. The staff could not locate current procedures for review. Please make these available (preferably prior to breakout) to aid discussion in understanding the proposed enhancements rendering the AMP consistent with that of GALL-LR, Revision 2, AMP, XI.S3.

2 B.2.3.31 B-182 The OE Section of LRA AMP B.2.3.31 states that during 2RF19 1. Please provide pictures taken Fall 2021 and 1RF22 Spring 2022 Outages of Units 2 and 1, during the inspections of the RV B-183 respectively, the RV supports were found acceptable but with supports indicating the described minor issues of peeling and flaking paint and boric acid in LRA AMP OE minor issues.

deposits. It is not clear what is the current status of the supports and how the aforementioned issues were resolved (particularly 2. Please discuss resolution of of boric acid deposits) to make them acceptable. issues noted in this question.

3 B.2.3.31 B-182 The LRA AMP in its OE Section states that the 1. Please clarify the relevance of the MSIP hardware to the structural The Unit 2 supports were reinspected after a failure of the supports (provide documentation Material Stress Improvement Process (MSIP) hardware, with no as necessary).

apparent change from previous inspections. It is not clear how the MSIP is relevant to the structural integrity for the noted RV 2. Indicate the importance of the supports. Was there an expectation that the MSIP failure could hardware regarding structural impact the structural integrity of the supports? If so, shouldnt integrity of the noted RV the MSIP hardware be included in the scope of LRA AMP supports.

B.2.2.31?

4 B.2.3.31 B-182 Boric acid solution could lead to corrosion of carbon or low alloy 1. Discuss how boric acid was steels with rates potentially reaching 1 in or greater deposited on the RV columns and annually. These corrosion rates are exacerbated particularly state its frequency of deposition, if when there is a substantial loss water by evaporation and/or any.

wet/dry oxygenation cycles. The increased concentration of the acid then leads to loss of material that is an applicable aging 2. Clarify how CPNPP determined effect that requires management. that the boric acid deposits at the supports did not constitute a non-CCNP CR-2021-003041 states that for 28 years the RV supports conforming condition or did not were not examined as they were determined to be necessitate cleaning/corrective inaccessible. CPNP 2RF19 Fall 2021 ISI Final Report dated action(s) otherwise required by October 29, 2021 and CPNP 1RF22 ISI Final Report dated May ASME Section XI, Subsection 5, 2022 state that remote VT-3 examination performed with a IWF-3410(a) requirements, fiberscope and flashlight, found the supports acceptable despite particularly when the performed the existence of corrosion and boric acid deposits. It is not clear VT-3 inspections were remote.

how the boric acid was deposited on the columns and whether the deposition was/is reoccurring or was it a onetime 3. If boric acid corrosion was/is a event. Given that the VT-3 exams were remote and the reoccurring event, there could be a challenges of the process in estimating corrosion levels, it is not measurable loss of material on the also clear how the applicant determined that the observed RV steel supports. Delineate corrosion at the supports was limited with no further action of measures taken and to be taken to cleaning/corrective measures needed to satisfy requirements of maintain the RV supports free of the ASME Code Section XI and 10CFR Part 50 and Appendix B, corrosion boric acid accumulation Criterion XVI. In addition, it is not clear whether the minimum so that they remain acceptable for design code-required RV column support section thickness and service for the period of extended integrity of bolting/welding connections had been maintained or operation, consistent with will be maintained for the period of extended operation. acceptance criteria of ASME Code Section XI, Subsection IWF 3410(a) included in GALL-LR Report, Revision 2, AMP XI.S3, Acceptance Criteria program element.

Comanche Peak Nuclear Power Plant, Units 1 and 2 License Renewal Application (LRA) Breakout Audit Questions LRA Section B.2.3.32 AMP: 10 CFR Part 50, Appendix J Question SLRA Section SLRA Page Background / Issue Discussion Question / Request Number (As applicable/needed) 1 B.2.3.32; B-185; 3.5-3 The SLRA and PBD (LUM00020-REPT-069, Rev 1, a. Walk through on Teams and Section 4.1.2) state that some components are discuss specific examples of 3.5.2.1.1 excluded from local leak rate testing (LLRT) under where and how the containment the CLB (as shown in FSAR Table 6.2.4-2). In pressure-retaining boundary those cases, aging effects associated with those components excluded from LLRTs components are managed by the following AMPs are captured for aging (list provided therein) management in the applicable SLRA Table 2s by the listed AMPs.

  • ASME XI ISI - IWB, IWC, IWD That is, identify the specific line
  • ASME XI ISI - IWE items in the applicable Table 2s that include the exempted
  • Water Chemistry component and each of the credited AMP(s).
  • Closed Treated Water Systems
b. Explain if and how AMPs such as
  • One-Time Inspection ISI - IWB, IWC, IWD; Closed
  • External Surfaces Monitoring Treated Water Systems, External Surfaces Monitoring, Flow-
  • Boric Acid Corrosion Accelerated Corrosion, Fatigue
  • Flow-Accelerated Corrosion Monitoring credited for containment pressure-retaining
  • Fatigue Monitoring boundary components excluded from Appendix J LLRTs include It is not clear to the staff where and how these these components within its excluded components are included in applicable scope.

SLRA Table 2s to demonstrate adequate aging management of such excluded components.

Additionally, SLRA Section 3.5.2.1.1 Containment

Buildings on page 3.5-3 does not include several of the AMPs listed above among the AMPs that manage aging effects for the containment building components.

The staff needs this information to verify consistency of the scope of program element of the 10 CFR 50, Appendix J AMP will the GALL-LR Report.

2 TS 5.5.16, 5.5-14, TS 5.5.16.a states: A program shall be established Explain the inconsistency between TS Amendment 173; to implement the leakage rate testing of the 5.5.16 and the referenced program B-184 containment as required by 10 CFR 50.54(o) and implementing procedures with respect to LRA B.2.3.32 10 CFR 50, Appendix J, Option B, as modified by the implementing documents for the approved exemptions. This program shall be in program and whether changes are accordance with the guidelines contained in NEI required to the implementing procedures.

94-01, Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J, Revision 3-A, dated July 2012, and the conditions and limitations specified in NEI 94-01, Revision 2A, dated October 2008, as modified by the following exceptions:

However, inconsistent with the above TS requirements, the program implementing procedures STA-743 (Rev 2-5), TSP-743 (0-3), and PPT-S2-7014 (Rev. 1) continue to reference RG 1.163 (Rev. 0 Sept 95), NEI 94-01 (1995, Rev 0) and ANSI N58.2-1994 as the implementing documents.

3 B.2.3.32 B-184 LRA states that the 10 CFR 50, Appendix J To verify adequate performance regarding program is an existing performance monitoring the containment leakage rate, provide a program. The SLRA does not provide a summary of summary of the results and date of the the results of the most recent U1 ILRT that was most recent ILRT for Unit 1.

scheduled for April 2022.

4 B.2.3.32 B-186 thru LRA B.2.3.32, under Plant-Specific OE, states, in Provide 3 most recent program health B-188 part: In addition AMPs, such as the 10 CFR self-assessments for the LRA B.2.3.32 Part 50, Appendix J AMP, will receive effectiveness AMP.

reviews every 5 years or as appropriate, in accordance with the guidance in NEI 14-12.

However, no documentation of recent program health/effectiveness self-assessment(s) for the AMP is discussed or provided on the ePortal.

Comanche Peak Nuclear Power Plant, Units 1 and 2 License Renewal Application (LRA) Breakout Audit Questions LRA Section B.2.3.33, Masonry Wall Question LRA/SLRA LRA/SLRA Background / Issue Discussion Question / Request Number Section Page (As applicable/needed) 1 Basis 7 of 20 GALL AMP XI.S5, Masonry Walls, element 3, notes that Please discuss why mortar joints and gaps Document gaps between supports and masonry walls should be between supports are not discussed in the monitored. GALL-SLR also mentions cracking or loss of implementing procedure.

LUM00020- material at mortar joints.

REPT-070 Section 4.3 in the basis document references a Section 4.3 degradation mechanism checklist for masonry walls which makes no mention of gaps between supports or mortar joints.

2 Basis 9 of 20 Element 5 of the basis document identifies several Please explain how these additional Document recommended actions from GALL-SLR and notes that actions are being addressed or why it is these actions are not necessary to meet the GALL unnecessary to implement them for the LUM00020- guidance but are warranted and addressed in Section 7 of PEO.

REPT-070 the basis document.

Section 4.5 It was unclear to the staff how these items were addressed in Section 7.

3 LRA Table 3.5-62 Item 3.5-1, 071 addresses freeze-thaw for masonry walls Please explain why this aging effect is not 3.5-1, 071 and is noted as not applicable. applicable to masonry walls exposed to an outdoor environment.

Comanche Peak is in a moderate weathering environment.

The GALL Report recommends aging management for this aging effect for accessible areas in this weathering environment.

Comanche Peak Nuclear Power Plant, Units 1 and 2 License Renewal Application (LRA) Breakout Audit Questions LRA Section B.2.3.34: Structures Monitoring Question LRA LRA Background / Issue Discussion Question / Request Number Section Page (As applicable/needed) 1 Table 3.5.2- 3.5-188 Note: This breakout question also applies to TRP 27, 1. Please discuss where these insulations and 15 Fire Protection. wraps, penetration seals, and penetration sleeves are located to be exposed to outdoor air.

LRA Table 3.5.2-15 includes silicate radiant energy If these fire barriers are not protected from shield, subliming compound, ceramic fiber/blanket, and weather, please discuss any impacts on the stainless steel insulation and wrap exposed to outdoor aging effects to be managed.

air. This table also includes elastomer penetration seals and carbon steel and stainless steel penetration sleeves 2. Please discuss what the specific ceramic exposed to outdoor air. fiber/blanket materials are.

Loss of material of the stainless steel insulation and 3. Please discuss how the Structures Monitoring wrap and penetration sleeve exposed to outdoor air in program is adequate to manage the aging LRA Table 3.5.2-15 are managed by the Structures effects for the stainless steel insulation and wrap Monitoring program (AMR Item 3.5-1, 093) and cites and penetration sleeve to ensure the Fire Barrier plant-specific Note 5, which states, Relative to intended function is maintained.

stainless-steel components located outdoors, the Structures Monitoring (B.2.3.34) AMP is focused on 4. Please discuss how the program descriptions areas with potential for frequent or prolonged water and procedures for the Structures Monitoring pooling and communicates with the Fire Protection and Fire Protection programs reflect this.

(B.2.3.15) AMP as warranted. Please note: Note E is an error.

This plant-specific note does not provide details on how the Structures Monitoring program is adequate to manage the aging effects for the stainless steel insulation and wrap and penetration sleeve to ensure the Fire Barrier intended function is maintained.

The staff notes that the discussion of AMR Item 3.5-1, 093 states, For stainless steel and aluminum, the focus

is on areas where water could pool or get within insulation jacketing.

The staff did not find information related to these stainless steel insulation and wrap and penetration sleeve in Structures Monitoring or Fire Protection program descriptions or documents on the portal Also Note: Table 2 items in Table 3.5.2-15, associated with NUREG-1801 Item III.B2.TP-6 and AMR item 3.5-1, 093, lists stainless steel penetration sleeve and insulation and wrap, which their aging effects are managed by the Structures Monitoring program. It cites Notes E, and C, respectively.

The staff verified that NUREG-1801 Item III.B2.TP-6 uses the Structures Monitoring program, Note E is an error.

2 B.2.3.34 B-192 The GALLLR Report AMP XI.S5 states that the steel Scope of the Program:

edge supports and steel bracings for masonry walls are considered component supports and aging effects are Clarify whether existing Structures Monitoring managed by the Structures Monitoring program. The program manages aging effects for the steel staff could not locate the inspection of steel edge edge supports and steel bracing for masonry supports and steel bracings for masonry walls in the walls.

Structures Monitoring AMP basis document. However, Section 8.5.2.3 in Procedure No. STI-744.09 states that steel members laterally support the masonry walls and these connections between the masonry and the support members should be examined.

3 B.2.3.34 B-192 1. Section 6.2 in Procedure No. STI-744.09 states that Scope of the Program:

all structures identified in Section 7.0 will be included Table 2.2-3 2.2-7 within the scope of the Structural Monitoring program. 1. Clarify whether inspection areas in question (from a to f) are within the scope of LR.

2.4.11 Section 7.0 in Procedure No. STI-744.09 lists the 2.4-29 following inspection areas:

a. Circulating water intake structure 2. Clarify whether existing Structures Monitoring program include the Firewater Valve Houses. If
b. Service water discharge structure not, provide the enhancement.
c. Plant effluent tanks
d. Demineralized water storage tank
e. foundation & appurtenances
f. Block wall enclosures for the fire water deluge valves for the transformers The staff notes that the AMP basis document does not include these inspection areas within the scope of LR.

LRA Table 2.2-3 indicates that the circulating water intake structure and service water discharge structure are not in the scope of LR.

2. LRA Section 2.4.11 includes the Firewater Valve Houses in the scope of LR. However, the staff could find the Firewater Valve Houses in the Section 7.0 of Procedure No. STI-744.09 and AMP basis document.

4 B2.3.34 B-193 The GALL-LR Report AMP XI.S6 states that preventative Preventative Actions:

actions emphasize proper selection of bolting material, AMP Basis 15 of 42 lubricants, and installation torque or tension to prevent or 1. Evaluate and revise to ensure that the document minimize loss of bolting preload and cracking of high enhancement to preventive actions in AMP will strength bolting. be consistent with the GALL-LR report recommendations.

AMP basis document states that design requirements and maintenance practices provide for proper selection 2. Check enhancements to preventative actions of bolting material and installation torque or tension of for structural bolting integrity in other AMPs to structural bolts and it also states that the storage ensure the consistency.

requirements of MDA-404 partially meet the storage requirement in Section 2.2 of the RCSC, and AMP provides an enhancement Reconcile the preventive actions in NUREG-1339, EPRI NP-5769, and EPRI

TR104213 with the existing procedures and practices for structural bolting.

It appears that AMP does not include preventative action of proper selection of lubricants, and AMPs enhancement is vague and needs to be specific.

5 B.2.3.34 B-192 The GALL-LR Report AMP XI.S6 states that structural Parameters monitored or inspected, and sealants are monitored for cracking, loss of material, and Acceptance criteria hardening, and structural sealants are acceptable if the observed loss of material, cracking, and hardening will Clarify whether there are structural sealants at not result in loss of sealing. CPNPP.

The staff could not locate structural sealants in the If yes, provide enhancements to Parameters Structures Monitoring AMP basis document and monitored or inspected, and Acceptance criteria Procedure No. STI-744.09. for structural sealants, also provide Table 1 and 2 items if necessary.

It is unclear whether there are structural sealants at CPNPP and how their aging effects are adequately managed.

6 B.2.3.34 B-192 1. The GALL-LR Report AMP XI.S6 states that In Detection of Aging Effect:

general, all structures and ground water quality are STI-744.09 11 of 34 monitored on a frequency not to exceed 5 years. Some 1. Clarify the inspection frequencies of all structures of lower safety significance, and subjected to structures in the LR Section B.2.34 benign environmental conditions, may be monitored at 2. Provide the justification why the inspection an interval exceeding five years; however, they should frequencies every 10 years for the settlement of be identified and listed, together with their operating Category I structures and component supports experience. are acceptable. and clarify what component LR Section B.2.3.34 only states that the frequency of supports are inspected once every ten years.

monitoring groundwater chemistry (pH, chlorides, and sulfates) is once every 5 years.

It appears that the Structures Monitoring program in Section B.2.3.34 lacks information of inspection frequency.

2. Section 7.0 in procedure No. STI-744.09, Revisions 0, Structural Monitoring Inspection Guide, provides the inspection frequency of structures and structural components, including the inspection frequency of every 10 years for the settlement of Category I structures.

Section 12.2 in procedure No. STI-744.09 also states that the component supports (Sampled) will be inspected 1 every ten years.

It is unclear to the staff why the inspection frequency of every 10 years is acceptable, and whats component supports are inspected once every ten years?

7 B2.3.34 B-192 The GALL-LR Report AMP XI.S6 states that the program Detection of Aging Effect:

includes provisions for more frequent inspections of AMP Basis 10 of 42 structures and components categorized as (a)(1) in Clarify whether the existing Structures document accordance with 10 CFR 50.65. Monitoring program includes provisions for more frequent inspections if a structure or component Section 3.3 in AMP basis document states, As cannot meet its applicable acceptance criteria.

described in Section 4.4.2 below the CPNPP Structures Monitoring AMP includes provisions for increased If yes, provide procedures and examples.

inspection frequencies if a structure or component Otherwise, provide the enhancement.

cannot meet its applicable acceptance criteria.

The staff could not locate provisions for more frequent inspections in Section 4.4.2 of the AMP basis document.

8 B.2.3.34 B-192 Section 3.3 in AMP basis document indicates Section Detection of Aging Effect:

4.4.2 to include an enhancement to the CPNPP Structures Monitoring AMP that outlines subsequent Provide the enhancement to the CPNPP steps if groundwater leakage is identified. Structures Monitoring AMP that outlines subsequent steps if groundwater leakage is The staff could not locate the above-mentioned identified.

enhancement in the AMP basis document and LRA.

9 B.2.3.34 B-194 The Structures Monitoring program has an Acceptance Criteria:

enhancement: provide guidance for documentation and archival requirements in accordance with ACI 349.3R Clarify the ACI Section for this enhancement.

Section 3.5. The staff reviewed ACI 349.3R and found that it is related to ACI 349.3R Section 3.4 instead of Section 3.5.

10 Table 3.3-1 3.3-76 The applicant claims that AMR item 3.3-1, 111 is not 1. Evaluate the applicability of AMR item 3.3-1, used, but states that the CPNPP new fuel storage racks 120 for AMR item 3.3-1, 111, and explain why 3.3-80 are stainless steel and addressed with item 3.3-1, 120. aging management is not required for the new Loss of material of structural steel exposed to indoor air fuel storage racks.

is addressed with item 3.5-1, 077 below.

2. Clarify where the Table 2 items for new fuel AMR item 3.3-1, 111 is to address aging effect of loss of storage racks are located.

material due to general, pitting, and crevice corrosion.

AMR 3.3-1, 120 has no aging effect without requiring AMP.

It is unclear to the staff how AMR item 3.3-1, 120 is related to AMR item 3.3-1, 111 due to different aging effects. In addition, the staff could not find new fuel storage racks Table 2 items associated with AMR item 3.3-1, 120.

11 Table 3.3-1 3.3-73 AMR item 3.3-1, 106 is to manage aging effect of loss of Explain why the Structures Monitoring program material due to general, pitting, crevice, and can be used to manage this aging effect instead Table 3.5.2- microbiologically influenced corrosion, which is managed of using the Buried and Underground Piping and 5 by the Buried and Underground Piping and Tanks Tanks AMP.

3.5-119 Table 3.5.2- (B.2.3.27) AMP.

8 3.5-138 AMR item 3.3-1, 106 in Table 3.3-1 states that Additionally, as listed in Tables 3.5.2-5 and 3.5.2-8, below grade piping penetrations for the FB and SWIS have coated steel plate collars exposed to soil that are managed by the Structures Monitoring AMP, which includes inspection of inaccessible components when excavated for other reasons. A generic note E and plant-specific note are used.

The Buried and Underground Piping and Tanks AMP is an existing preventive,

mitigative, and condition monitoring AMP that manages the aging effects associated with the external surfaces of buried and underground piping and tanks for loss of material and loss of coating integrity. Components addressed by this program, fabricated of steel, use preventive and mitigative techniques including external coatings, cathodic protection, and quality backfill.

However, the Structures Monitoring program is only a condition monitoring AMP, it does not provide preventive and mitigative measures.

12 Table 3.5-1 3.5-55, AMR item 3.5-1, 054 in Table 3.5-1 states Consistent 1. Revise Table 1 items 3.5-1, 054, 063 and 067 with NUREG-1801 for Group 1, 3, 4, 5, and 7 structures, to include the Group 8: foundations.

and 3.5-59 as well as accessible areas of the SWIS (Group 6 structure) that are above-grade/water-line. 2. Clarify where Table 2 items for the 3.5.2.2.2 3.5-61 foundations in Group 8 are located for the AMR and AMR item 3.5-1, 063 in Table 3.5-1 states that the items 3.5-1, 054, 063, and 067.

Structures Monitoring AMP will be used to manage 3.5-27 increase in porosity and permeability and loss of strength for accessible exterior concrete in Group 1, 3, 5 and 7 structures exposed to flowing water in the form of heavy drainage of rainwater.

AMR item 3.5-1, 067 in Table 3.5-1 states the Structures Monitoring AMP will be used to manage increase in porosity and permeability, cracking, and loss of material of inaccessible concrete in Groups 1, 3 through 7 structures.

LRA Section 3.5.2.2.2 states that Group 8: Missile doors (The steel FWSTs are addressed in Section 3.5.2.1.11 whereas the foundations are considered with Group 3),

and Group 3 includes AB, DGBs, SGBs, Switchgear Buildings, Switchyard Structures, TBs, Yard Structures.

It appears that AMR items 3.5-1, 054, 063, and 067 shall include Group 8, foundations. The staff also could not locate Table 2 items for the foundations in Group 8.

13 Table 3.5-1 3.5-60 The applicant claims AMR item 3.5-1, 070 to be Explain how the applicant determined what consistent with NUREG-1801. The Masonry Walls AMP masonry walls are managed by both Masonry 3.5-62 will be used to manage cracking of masonry walls Walls and Structures Monitoring programs.

exposed to indoor air and outdoor air. However, the staff noticed in AMR item 3.5-1, 066 that the applicant uses the Structural Monitoring program to manage concrete aging effect for masonry walls conservatively. The staff also noticed that not all of masonry walls are managed by the Structures Monitoring program.

For example, masonry walls in Table 3.5.2-3 have AMR item 3.5-1, 070 without AMR item 3.5-1, 066. In addition, two AMR items for masonry block commodity Wall, floor, and ceiling in Table 3.5.2-15 associated with GALL item III.A3.T-12 have AMR item 3.5-1, 070 without AMR item 3.5-1, 066.

It is unclear why some masonry walls are managed by both AMPs but other masonry walls are only managed by the Masonry Walls AMP.

14 A.2.2.34 A-27 1. LRA Section A.2.2.34 states that the structures are 1. Update the inspection frequency in UFSAR monitored on an interval not to exceed 5 years. Supplement Section A.2.2.34 based on the applicants response to question number 6.

2. SRP-LR FSAR Supplement in the Table 3.0-1 states that this program is implemented in accordance with 2. Update the LRA Section A.2.2.34 to be NUMARC 93-01, Rev. 2 and RG 1.160, Rev. 2. The staff consistent with SRP-LR FSAR Supplement.

could not find this statement in LRA Section A.2.2.34.

15 Table 3.5-1 3.5-37 SRP-LR shows the title of Table 3.5-1 as Summary of Table 3.5-1 title is confusing and not accurate.

Aging Management Programs for Containments, Structures and Component Supports Evaluated in This is an editorial comment.

Chapters II and III of the GALL Report.

The title of LRA Table 3.5-1 is Summary of Aging Management Programs for Containment Building and Internal Structural Components.

Comanche Peak Nuclear Power Plant, Units 1 and 2 License Renewal Application (LRA) Breakout Audit Questions LRA Section B.2.3.35: Inspection of Water-Control Structures Question LRA LRA Background / Issue Discussion Question / Request Number Section Page (As applicable/needed) 1 A.2.2.35 A-27 LRA Section A.2.2.35 states that the structures within Scope of the Program and UFSAR the scope of the RG 1.127, Inspection of Water-Control Supplement:

B.2.3.35 B-197 Structures Associated with Nuclear Power Plants AMP include the 1. Clarify the scope of the Water-Control 2.4.7 2.4.8 2.4-21 Structures SRP-LR 2.4-22 Safe Shutdown Impoundment (SSI) and Dam, Service Table 3.0- Water Intake Channel, debris and fish barrier system, 2. Confirm that Tables 2.4-7 and 2.4-8 include all 3.0-24 the discharge canal, and the SWIS interior concrete components subject to aging management review 1 for the water-control structures based on the exposed to water-flow.

response to the question above, otherwise revise LRA Section B.2.3.35 states that the structures within Table 1 and 2 items accordingly.

the scope of the RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants AMP 3. Update the LRA and UFSAR supplement to include the SSI and Dam, portions of the Service Water ensure the consistency.

Intake structure exposed to water-flowing, the Service Water Intake Channel, debris and fish barrier system and the discharge canal.

Section 2.4.7 is about Safe Shutdown Impoundment and Dam. Section 2.4.8 states that The SWIS provides housing to the nuclear safety related service water pumps and a Non-Nuclear Safety Related (NNS) fire pump and is equipped with trash racks, traveling screens, stop gates, and screen wash pumps. But it does not discuss the Service Water Intake Channel and the discharge canal.

SRP-LR Table 3.0-1 FSAR Supplement states that the program includes structural steel and structural bolting

associated with water-control structures, steel or wood piles and sheeting required for the stability of embankments and channel slopes, and miscellaneous steel, such as sluice gates and trash racks. It appears that LRA UFSAR supplement is not consistent with the SRP-LR report recommendations.

2 B.2.3.35 B-197 The Inspection of Water-Control Structures program is Preventive Actions, Detection of Aging Effects, an existing AMP and is implemented as part of the and Acceptance Criteria:

Structures Monitoring program. Both AMPs use the same procedure. Evaluate what enhancements of the Structures Monitoring program will be applied to the The staff notes that the Structures Monitoring program Inspection of Water-Control Structures program has some enhancements that the Inspection of Water- and provide the enhancements to the Inspection Control Structures does not have. of Water-Control Structures program if necessary.

For example, the AMP basis document in Section 4.4.2 states that the qualifications requirement for the inspection of structures and components as well the requirements for the reviewer will be updated to match the ACI 349.3R current code requirements.

3 Table 3.5- 3.5-56 AMR item 3.5-1, 056 in GALL-LR report includes the Evaluate and identify the concrete components 1 concrete elements for exterior above grade and below subject to AMR for this aging effect, and revise grade concrete, foundation, and interior slab. Table 1 and 2 items accordingly.

Table 3.5.2-8 3.5-136 AMR item 3.5-1, 056 in Table 3.5-1 states that the RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants AMP will be used to manage loss of material for exterior above grade and below-grade concrete exposed to flowing water. It appears that AMR item 3.5-1, 056 misses the concrete elements for foundation and interior slab.

Table 2 item associated with AMR item 3.5-1, 056 in Table 3.5.2-8 only shows component as concrete:

interior. This Table 2 item does not include other concrete components requiring aging management.

4 Table 3.5- 3.5-57 AMR item 3.5-1, 059 in Table 3.5-1 states that the RG Evaluate and identify the concrete components 1 1.127, Inspection of Water-Control Structures subject to AMR for this aging effect, and revise Associated with Nuclear Power Plants AMP will be used Table 2 items accordingly.

Table to manage cracking, loss of bond, and loss of material 3.5.2-8 3.5-135 of the accessible above-grade, below-grade, and interior concrete in the SWIS.

Table 2 item associated with AMR item 3.5-1, 059 in Table 3.5.2-8 only shows component as concrete:

interior. This Table 2 item does not include other concrete components requiring aging management.

Please note that GALL-LR report refers to all accessible concrete areas for this AMR item.

5 Table 3.5- 3.5-58 The applicant claims AMR item 3.5-1, 060 to be not Evaluate the claim of no-applicability of AMR item 1 applicable. CPNPP is located in a region where 3.5-1, 060, and provide table 2 items if weathering conditions are considered moderate, as necessary.

shown in ASTM C33-90, Figure 1. Therefore, loss of material (spalling, scaling) and cracking due to freeze-thaw is an applicable aging effect and subject to AMR.

6 Table 3.5-176 Table 3.5.2-13 lists the carbon steel support for ASME Clarify where this commodity (ASME Class 3 3.5.2-13 Class 3 component exposed to raw water environment component) is used.

that cites Note E, its aging effect will be managed by ASME Section XI, Subsection IWF program. This AMR item is associated with GALL item III.A6.TP-221 and AMR item 3.5-1, 083.

The staff noted that GALL item III.A6.TP-221 and AMR item 3.5-1, 083 is used for the structural bolting in the water-control structures. It is unclear the staff whether the applicant uses GALL item properly.

Comanche Peak Nuclear Power Plant, Units 1 and 2 License Renewal Application (LRA) Breakout Audit Questions LRA Sections 4.6.1 & 4.6.2 TLAAs: Containment Liner Plate and Penetrations Fatigue Analyses Question SLRA SLRA Background / Issue Discussion Question / Request Number Section Page (As applicable/needed) 1 4.6.1, A.3.5.1 4.6-1, LRA Sections 4.6.1 & A.3.5.1 related to containment a. State the liner plate material based on 4.6-2, A- liner plate fatigue do not make any mention of the which the described fatigue waiver 39, A-40 material of the liner plate based on which the fatigue analysis was performed.

waiver analysis described was performed.

b. Explain or clarify if the material used in the analyses is bounding or enveloping, with regard to fatigue, of all materials used for the containment liner plate and its anchorage or integral attachments, as applicable, for which the LRA 4.6.1 TLAA is credited.

2 4.6.1, A.3.5.1 4.6-1,

  • LRA Section 4.6.1 references LRA Section 4.3.1 a. Explain or clarify the noted 4.6-2, A- and LRA Table 4.3.1-2 with regard to transient inconsistency between the number of 39, A-40 cycles considered for the containment liner plate. OBE and SSE cycles used in the TLAA Althougj it is consistent with the cycles used in in LRA 4.6.1 and the referenced LRA the audited Calculation 16345/6-CS(B)-028, Rev Table 4.3.1-2, specifically in terms of 1 on the ePortal, the staff notes an inconsistency number of OBE/SSE cycles and regarding the number of OBE and SSE cycles events.

between LRA Section 4.6.1 and referenced LRA Table 4.3.1-2. b. Provide a revised LRA A.3.5.1 FSAR supplement liner plate summary

  • The LRA Section A.3.5.1 FSAR supplement description that includes a summary of description for the containment liner plate TLAA all the transient cycles considered in the makes no mention of the OBE/SSE cycles fatigue waiver analysis of the evaluated in the containment liner plate fatigue containment liner plate consistent with waiver analysis; therefore, the FSAR summary LRA Section 4.6.1.

description appears incomplete.

3 4.6.2, A.3.5.2 4.6-2 LRA Sections 4.6.2 & A.3.5.2 related to containment a. State the containment penetrations thru 4.6- penetrations fatigue do not make any mention of the material based on which the described 4, A-40 material of the penetrations based on which the fatigue fatigue waiver analysis was performed.

waiver analysis described was performed.

b. Explain or clarify if the material used in the analyses is bounding or enveloping, with regard to fatigue, of all materials used for the containment process piping penetrations, as applicable, for which the LRA 4.6.2 TLAA is credited.

Comanche Peak Nuclear Power Plant, Units 1 and 2 License Renewal Application (LRA) Breakout Audit Questions LRA Section 3.5.2.2, AMR Results for Which Further Evaluation is Recommended by the GALL Report Question LRA LRA Background / Issue Discussion Question / Request Number Section Page (As applicable/needed) 1 3.5.2.2.1.2 3.5-20 The GALL Report recommends that a plant-specific 1. Explain how the elevated temperatures evaluation be performed if any portion of the concrete (above 250F) at local areas will be Table 3.5.2-1 3.5-85 containment components exceeds specified temperature adequately managed not to exceed the limits, i.e., general specified temperature limit, and whats the AMP?

temperature greater than 66°C (150°F) and local area temperature greater than 93°C (200°F). 2. Explain why the thermal insulations with material of calcium silicate are not

1. Section 3.5.2.2.1.2 states that local area temperatures subject to aging management.

may be elevated above general area temperatures due to process piping carrying high temperature fluids (e.g., MS, 3. Explain why thermal insulation can use and feedwater piping RCB penetrations and RCL cold SRP-LR item III.B1.1.TP-8, and why the and hot leg piping through the biological shield tunnel in thermal insulations with material of the primary shield wall), for example, feedwater stainless steel are not subject to aging temperatures are above 250F when main feedwater is management.

preheated prior to this switch. To comply with the requirements of ASME Section III, Division 2, paragraph 4. Evaluate whether a plant-specific CC-3430 on concrete temperatures, the unit 2 cold program is required?

penetrations (MV-17, MV-18, MV-19, and MV-20) along the preheater bypass flow path, are subject to an administrative time limit of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> for operating temperatures above 250F.

Section 3.5.2.2.1.2 also states that the RCB penetration and reactor coolant piping insulation contributes to keeping the local concrete temperatures of the RCB and PSW below 200F during normal plant operation.

2. Table 2 item in Table 3.5.2-1 lists a component of thermal insulation (high temperature penetrations) with material of calcium silicate and cites generic note H without aging management. It is unclear why aging management is not required.
3. Table 2 item associated with AMR item 3.5-1, 095 in Table 3.5.2-1 lists a component of thermal insulation (high temperature penetration) with material of stainless steel and cites generic note C without aging management.

SRP-LR item III.B1.1.TP-8 (AMR item 3.5-1, 095) lists a component (Aluminum, galvanized steel and stainless steel Support members; welds; bolted connections; support anchorage to building structure exposed to air-indoor uncontrolled environment.

This component does not include thermal insulation.

It is unclear how thermal insulation can use SRP-LR item III.B1.1.TP-8, and it is not clear why thermal insulations are not subject to AMR.

2 3.5.2.2.1.7 3.5-24 SRP-LR Section 3.5.3.2.1.7 states that a plant-specific 1. Evaluate the claim of no-applicability of program is not required if documented evidence confirms AMR item 3.5-1, 011 and 018 and Table 3.5-1 3.5-39 that where the existing concrete had air content of 3% to provide table 2 items if necessary.

Table 3.5-1 3.5-41 8% and subsequent inspection did not exhibit degradation related to freeze-thaw. 2. Clarify air content of the concrete mix used for the containment structure at

1. The applicant claims AMR item 3.5-1, 011 and 018 to CPNPP.

be not applicable. Section 3.5.2.2.1.7 states that CPNPP is located in a region where weathering conditions are 3. Evaluate whether a plant-specific considered moderate, as shown in ASTM C33-90, Figure program is required.

1. Therefore, loss of material (spalling, scaling) and 4. Explain what AMPs will be used and cracking due to freeze-thaw is an applicable aging effect how these AMPs will manage aging and subject to AMR. effect of freeze-thaw in inaccessible
2. Section 3.5.2.2.1.7 states that air entrainment content areas.

conformed to the design requirements of ACI 211.1 and was determined by ASTM C231. It is unclear to the staff

whats air content of concrete mix used for the containment structure at CPNPP.

3. Section 3.5.2.2.1.7 lacks the evaluation whether plant-specific program is required for managing this aging effect.
4. Section 3.5.2.2.1.7 lacks information of how aging effect in inaccessible areas will be managed.

3 Table 3.5-1 3.5-42 Note: This breakout question also applies to TRP 42, Clarify whether the ASME XI Subsection IWL ASME XI Subsection IWL program program needs an enhancement for the inspection of ASR.

AMR 3.5-1, 019 in Table 3.5-1 states that the ASME Section XI, Subsection IWL AMP will continue to inspect and monitor for cracking and indications of ASR-induced degradation.

The staff notes that the Structures Monitoring program has an enhancement to the Parameters Monitored or Inspected, Visually inspect concrete structures for unique cracking such as "craze", "mapping" or "patterned" cracking to determine the presence of alkali-silica gel.

The staff does not find similar enhancement in the ASME XI Subsection IWL program.

Comanche Peak Nuclear Power Plant, Units 1 and 2 License Renewal Application (LRA) Breakout Audit Questions LRA Section 3.5.2.2, AMR Results for Which Further Evaluation is Recommended by the GALL Report Inaccessible areas Question LRA Section LRA Background / Issue Discussion Question / Request Number Page (As applicable/needed) 1 3.5.2.2.2.1.1 3.5-27 SRP-LR Section 3.5.3.2.2.1.1 states that a plant- 1. Evaluate the claim of no-applicability of specific program is not required if documented AMR item 3.5-1, 042, and provide table 2 Table 3.5-1 3.5-48 evidence confirms that where the existing items if necessary.

concrete had air content of 3% to 8% and subsequent 2. Revise Table 1 item 3.5-1, 042 to include inspection did not exhibit degradation related to Group 8: foundations, and clarify whether freeze-thaw. the foundations in Group 8 meet the air-entrainment and water-cement-ratio of

1. The applicant claims AMR item 3.5-1, 042 to be not ACI 318-71.

applicable. Section 3.5.2.2.2.1.1 states that CPNPP is located in a region where weathering conditions are 3. Clarify air content of the concrete mix considered moderate, as shown in ASTM C33-90, used for the non-containment structures Figure 1. Therefore, loss of material (spalling, scaling) at CPNPP.

and cracking due to freeze-thaw is an applicable aging effect and is subject to AMR. 4. Evaluate whether a plant-specific program is required.

2. Section 3.5.2.2.2.1.1 states that non-containment structures at CPNPP consist of Groups 1, and 3 through 8. However, AMR item 3.5-1, 042 in Table 3.5-1 states that CPNPP is located in a moderate weathering region with concrete, for group 1, 3-5 and 7 structures, that meet the air-entrainment and water-cement-ratio of ACI 318-71, and the Structures Monitoring AMP is credited with management of other aging effects for the concrete foundations of group 1, 3-5, and 7 structures.

LRA Section 3.5.2.2.2 states that Group 8: Missile doors (The steel FWSTs are addressed in Section 3.5.2.1.11 whereas the foundations are considered with Group 3), and Group 3 includes AB, DGBs, SGBs, Switchgear Buildings, Switchyard Structures, TBs, Yard Structures.

It appears that AMR items 3.5-1, 042, shall include Group 8, foundations. In addition, it is not clear to the staff whether the foundations in Group 8 meet the air-entrainment and water-cement-ratio of ACI 318-71.

3. Section 3.5.2.2.2.1.1 states that air entrainment content conformed to the design requirements of ACI 211.1 and was determined by ASTM C231.

It is unclear to the staff whats air content of concrete mix used for the non-containment structures at CPNPP.

4. Section 3.5.2.2.2.1.1 lacks the evaluation whether a plant-specific program is required for managing this aging effect.

2 3.5.2.2.2 3.5-27 1. Section 3.5.2.2.2.1.2 mentioned petrographic 1. Provide the results of petrographic examination and its results. examination for the staff to review.

3.5.2.2.2.1.2 3.5-28

2. The AMR item 3.5-1, 043 in Table 3.5-1 states that 2. Revise Table 1 item 3.5-1, 043 to include Table 3.5-1 3.5-49 the Structures Monitoring AMP is credited with Group 8: foundations, and clarify where managing cracking due to reaction with aggregates Table 2 items for Group 8 foundations (such as ASR), for CPNPP group 1, 3-5, and 7 are located.

structures, including inaccessible areas.

3. Explain why different notes A and E are Section 3.5.2.2.2.1.2 states that non-containment cited for the Structures Monitoring structures at CPNPP consist of Groups 1, and 3 program for the further evaluation through 8. sections.

Section 3.5.2.2.2 lists Group 8: Missile doors (The steel FWSTs are addressed in Section 3.5.2.1.11

whereas the foundations are considered with Group 3).

It appears that AMR items 3.5-1, 042, shall include Group 8, foundations. In addition, the staff could not locate Table 2 items for the foundation in Group 8.

3. Table 2 items associated with AMR item 3.5-1, 043 in Table 3.5.2-1 cite Note E, while the rest of Table 2 items associated with AMR item 3.5.1-043 in Tables 3.5.2-2 thru 3.5.2-6, and Tables 3.5.2-9 thru 3.5.2-12 cite Note A for Structures Monitoring program. The staff noticed that other AMR items cite Note E for the AMP when further evaluation is required to determine if a plant-specific aging management program is needed.

Per SLR-ISG-2021-03-STRUCTURES, AMP for AMR item 3.5-1, 043 is revised to Plant-specific aging Management program or AMP XI.S6, Structures Monitoring, enhanced as Necessary when further evaluation is required.

3 3.5.2.2.2.1.3 3.5-29 1. Section 3.5.2.2.2.1.3 mentioned that the Seismic 1. Clarify whether porous sub-foundations Category I concrete structure walls and columns are are used at CPNPP site.

Table 3.5-1 3.5-50 supported on thick continuous concrete base mats which rest on the rock subgrade with the exception of 2. Evaluate the claim of non-applicability of the Category I tanks and pipe tunnels. It is not clear to AMR item 3.5-1, 046, and provide table 2 the staff whether porous concrete sub-foundations are items if necessary.

present at CPNPP site. 3. Clarify the note citation for Table 2 items

2. AMR 3.5-1, 046 is related to aging effect of associated with AMR item 3.5-1, 044 for reduction of foundation strength and cracking due the Structures Monitoring program.

to differential settlement and erosion of porous concrete sub-foundation. The applicant claims AMR item 3.5-1, 046 to be not applicable. This aging effect is related to a). differential settlement, b) porous sub-

foundation. This aging effect exists if either or both conditions present.

3. Table 2 items associated with AMR item 3.5-1, 044 cite Note A for the Structures Monitoring program, while Table 2 items associated with 3.5-1, 047 cite Note E for the Structures Monitoring program. It is not consistent for the AMP note citation in the further evaluation.

Per SLR-ISG-2021-03-STRUCTURES, AMP is revised to Plant-specific aging Management program or AMP XI.S6, Structures Monitoring, enhanced as Necessary when further evaluation is required.

4 3.5.2.2.2.1.4 3.5-30 1. Section 3.5.2.2.2.1.4 states 1. Clarify whether there is OE for the increase in porosity and permeability and Table 3.5-1 3.5-51 Leaching of calcium hydroxide or carbonation has not loss of strength due to leaching of occurred for above-grade concrete at CPNPP. It is calcium hydroxide or carbonation in unclear to the staff whether there is OE in below-grade below-grade interior concrete walls or interior concrete walls. any other locations at CPNPP. If yes,

2. AMR item 3.5-047 in Table 3.5-1 states Consistent provide evaluation whether the observed with the OE reflected in SLR-ISG-2021 leaching of calcium hydroxide and STRUCTURES, a plant-specific AMP is not required carbonation in accessible areas has for inaccessible concrete areas of Group 1, and 3 impact on the intended function at structures with foundations exposed to groundwater. It CPNPP site.

appears that it does not include Groups 4, 5, 7 and 8. 2. Explain why a plant-specific program is SRP-LR Section 3.5.3.2.2.1.4 states that a plant- not required for Groups 1-5, 7-9, and specific aging management program is not required for update the LRA accordingly.

the reinforced concrete exposed to flowing water if (1) there is evidence in the accessible areas that the flowing water has not caused leaching of calcium hydroxide and carbonation or (2) evaluation determined that the observed leaching of calcium hydroxide and carbonation in accessible areas has no

impact on the intended function of the concrete structure.

Note: Per GALL-LR definition in Table IX.D, water-flowing includes rainwater, raw water, ground water, or water flowing under a foundation.

5 3.5.2.2.2.3.1 3.5-32 SRP-LR Section 3.5.3.2.2.3 states that a plant-specific 1. Evaluate the claim of no-applicability of program is not required if documented evidence AMR item 3.5-1, 049, and provide table 2 Table 3.5-1 3.5-52 confirms that where the existing concrete had air items if necessary.

content of 3% to 8% and subsequent inspection of accessible areas did not exhibit degradation related 2. Clarify air content of the concrete mix to freeze-thaw. used for the water-control structures at CPNPP.

1. AMR item 3.5-1, 049 claims to be not applicable, and the loss of material (spalling, scaling) and cracking 3. Evaluate whether a plant-specific due to program is required.

freeze-thaw does not apply to the CPNPP SWIS or 4. Explain how and what AMP will manage SSI and Dam. this aging effect in below grade inaccessible concrete areas.

Section 3.5.2.2.2.3.1 states that CPNPP structures, including SWIS, are located in a region where weathering conditions are considered moderate, as shown in ASTM C33-90, Figure 1. Therefore, loss of material (spalling, scaling) and cracking due to freeze-thaw is an applicable aging effect and subject to AMR.

2. Section 3.5.2.2.2.3.1 states that air entrainment content conformed to the design requirements of ACI 211.1 and was determined by ASTM C231. AMR item 3.5-1, 049 in Table 3.5-1 states that SWIS concrete meet the air-entrainment and water-cement ratio of ACI 318-71. It is unclear to the staff whats air content of concrete mix used for the water-control structures at CPNPP.
3. Section 3.5.2.2.2.3.1 lacks the evaluation whether a plant-specific program is required for managing this aging effect.
4. Section 3.2.2.2.2.3.1 mentions the Inspection of Water-Control Structures AMP and the Structures Monitoring AMP for certain inspections. It is not clear to the staff how and what AMP will manage this aging effect in below grade inaccessible concrete areas of Group 6 structures.

6 3.5.2.2.2.3.2 3.5-33 1. Section 3.5.2.2.2.3.2 states that cracking due to 1. Clarify which AMP is used for the aging expansion and reaction with aggregates is an management.

Table 3.5-1 3.5-53 applicable aging effect in below-grade inaccessible concrete areas for CPNPP Group 6 structures and will 2. Explain how AMP will manage aging be managed by the Inspection of Water-Control effect in below-grade inaccessible Structures AMP and the Structures Monitoring AMP. concrete areas.

However, AMR item 3.5-1, 050 in Table 3.5-1 only credits the Structures Monitoring program for this aging effect.

2. Section 3.5.2.2.2.3.2 lacks information how to manage this aging effect in below grade inaccessible concrete areas.

7 3.5.2.2.2.3.3 3.5-33 1. Section 3.5.2.2.2.3.3 states that the Inspection of 1. Clarify which AMP is used for the aging Water-Control Structures program and the Structures management.

Table 3.5-1 3.5-54 Monitoring program will manage the aging effect.

However, AMR item 3.5-1, 051 in Table 3.5-1 and 2. Clarify whether OE related to leaching associated Table 2 items only credit the Structures exists in accessible areas of the water-Monitoring program for this aging effect. control structures. If yes, provide evaluation whether the observed

2. Section 3.5.2.2.2.3.3 does not present OE related to leaching of calcium hydroxide and the leaching in accessible areas of the water-control carbonation in accessible areas has structures, which is the basis for evaluating whether a impact on the intended function.

plant-specific AMP is required.

3. Explain why a plant-specific AMP is not required.
3. AMR item 3.5-1, 051 in Table 3.5-1 states that a 4. Explain how AMP will manage aging plant-specific AMP is not required for the inaccessible effect in below-grade inaccessible areas of the CPNPP SWIS (Group 6) structure, but it concrete areas.

does not explain the reason.

4. Section 3.5.2.2.2.3.1 lacks information how to manage aging effects in below grade inaccessible concrete areas.

8 Table 3.5-1 3.5-41, This breakout question also applies to TRP 42. Evaluate the claim of no-applicability of AMR 3.5-43 item 3.5-1, 016 and 024, and explain what and AMR items 3.5-1, 016 and 024 note that increase in how AMP will manage this aging effect in below porosity and permeability; cracking; loss of material grade inaccessible and accessible concrete (spalling, scaling) due to aggressive chemical attack is areas as applicable and provide table 2 items if not an aging effect requiring management because the necessary.

concrete is not exposed to acidic solutions with a pH <

5.5, chloride solutions > 500ppm, or sulfate solutions >

1500ppm. AMR item 3.5-1, 067 notes that the SMP will manage this aging effect for similar concrete. It is not clear why the aging effect in items 016 and 024 are not applicable. This aging effect exists in the environment as long as acidic solutions present, concrete deterioration may differ.

9 Table 3.5-1 3.5-59 The applicant claims AMR item 3.5-1, 064 to be not Evaluate the claim of no-applicability of AMR applicable. CPNPP is located in a region where item 3.5-1, 064, and provide table 2 items if weathering conditions are considered moderate, as necessary.

shown in ASTM C33-90, Figure 1. Therefore, loss of material (spalling, scaling) and cracking due to freeze-thaw is an applicable aging effect and subject to AMR.

10 Table 3.5-1 3.5-60 SRP-LR Report lists the following components for 1. Revise AMR 3.5-1, 065 notes in Table AMR item 3.5-1, 065: 3.5-1 to ensure the consistency with SRP-LR report recommended Groups

a. Groups 1-3, 5, 7-9: concrete (inaccessible and concrete areas.

areas): below-grade exterior; foundation;

2. Clarify whether aging effects for Groups 5, 7, and 8 structures, as well as certain
b. Groups 1-3, 5, 7-9: concrete (accessible Group 3 structures are managed by the areas): below-grade exterior; foundation, Structures Monitoring program, and provide Table 2 items if necessary
c. Groups 6: concrete (inaccessible areas): all AMR item 3.5-1, 065 in Table 3.5-1 states that the Structures Monitoring AMP will be used to manage cracking, loss of bond, and loss of material of inaccessible concrete in Groups 1, 3 and 6 structures exposed to a groundwater/soil environment.

It also states that Group 5, and 7 structures, as well as certain Group 3 structures are founded above the water-table. Cracking; loss of bond; and loss of material (spalling, scaling) due to corrosion of embedded steel is an applicable aging effect, where the water table is one of factors causing this aging effect.

Section 3.5.2.2.2 lists Group 8: Missile doors (The steel FWSTs are addressed in Section 3.5.2.1.11 whereas the foundations are considered with Group 3).

It is unclear whether aging effects for Groups 5, 7, and 8 structures, as well as certain Group 3 structures are managed by the Structures Monitoring program.

Comanche Peak Nuclear Power Plant, Units 1 and 2 License Renewal Application (LRA) Breakout Audit Questions LRA Section 3.5.2.2, AMR Results for Which Further Evaluation is Recommended by the GALL Report Settlement Question LRA Section LRA Background / Issue Discussion Question / Request Number Page (As applicable/needed) 1 3.5.2.2.1.2 3.5-19 1. Section 3.5.2.2.1.2 states that reduction of foundation 1. Evaluate the claim of non-applicability strength and cracking due to differential settlement and of AMR item 3.5-1, 002, and provide Table 3.5-1 3.5-37 erosion of porous concrete sub-foundation is not an table 2 items if necessary.

applicable aging effect for the CPNPP RCB, and AMR item 3.5-1, 002 claims to be not applicable. The staff 2. Clarify the note citation for Table 2 understands that RCB is not founded on a porous items associated with AMR item 3.5-1, concrete sub-foundation. Differential settlement might be 001 for the Structures Monitoring small but requires Structures Monitoring to monitor. program.

Therefore, reduction of foundation strength and cracking due to differential settlement and erosion of porous concrete sub-foundation is an applicable aging effect.

2. Table 2 items associated with AMR item 3.5-1, 001 cite Note A for the Structures Monitoring program, while Table 2 items associated with other AMR items cite Note E for the Structures Monitoring program when the further evaluation is required.

Per SLR-ISG-2021-03-STRUCTURES, AMP is revised to Plant-specific aging Management program or AMP XI.S6, Structures Monitoring, enhanced as Necessary when further evaluation is required.

Comanche Peak Nuclear Power Plant, Units 1 and 2 License Renewal Application (LRA) Breakout Audit Questions Supports (LRA Section B.2.3.34. Structures Monitoring)

Question LRA LRA Page Background / Issue Discussion Question/Request Number Section (As applicable/needed) 1 OE Applicant A number of routine walkdowns identified pipe supports Discuss steps taken to ensure that pins are provided that were degraded, loose, or hangers having missing adequately deformed so that they can TR-2021- OE pins, and/or needing pins replaced/reworked. CPNPP remain in place following application of 003756 Units 1 and 2 Specifications for Structural design basis loads. For those hangers CR-2017- Steel/Miscellaneous Steel (Cat I, II & Non-Seismic) 2323- identified as having missing pins discuss 004316 SS-16B, Rev 14, paragraph 3.13.7.5 emphasizes shall steps taken to rectify/ensure their be sufficiently deformed to prevent withdrawal. It is not operability.

CR-2015- clear whether pins were missing because they were not 009667 sufficiently deformed and withdrew under applied loads. It is also not clear how supports lacking cotter pins can CR-2013-maintain their structural integrity.

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