ML25253A040

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Breakout Questions - Aging Management Audit - Robinson Unit 2 SLR
ML25253A040
Person / Time
Site: Robinson Duke Energy icon.png
Issue date: 08/22/2025
From: Alexandra Siwy
NRC/NRR/DNRL/NLRP
To:
References
Download: ML25253A040 (128)
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BREAKOUT QUESTIONS Aging Management Audit H.B. Robinson Steam Station, Unit 2 Subsequent License Renewal Application April 28, 2025 - August 22, 2025

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 2

Cable Bus Question Number SLRA Section SLRA Page Background / Issue Discussion Question / Request 1

3.6.2.2, B2.1.37 B -

10667, B - 222 NUREG 2192 (SRP-SLR) Section 3.6.2.2.2 states: GALL-SLR Report Aging Management Program (AMP) XI.E1 calls for a visual inspection of accessible insulated cables and connections subject to an adverse localized environment which may not be applicable to cable bus due to inaccessibility or applicability of the aging mechanisms and effects.

Robinson SLRA Section 3.6.2.2.2 states: [3.6.1-029] -

Reduced electrical insulation resistance for the cable bus insulated electrical cables is the same aging effect as for other installed insulated electrical cables. This item is similar to electrical insulation for electrical cables and connections item [3.6.1-008], so this aging effect will be managed by the Electrical Insulation for Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements (B2.1.37) program.

SLRA B2.1.37 states: The Electrical Insulation for Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification (EQ) Requirements aging management program is an existing condition monitoring program that will continue to manage the aging effect of reduced insulation resistance of accessible non-EQ electrical cable and connection insulation in adverse localized environments. At least once every ten years, accessible insulated cables and connections installed in adverse localized environments are visually inspected for jacket surface anomalies such as embrittlement, discoloration, Explain how Robinson expects to manage the aging effect of the insulation of the cable bus by B2.1.37 if the cable buss insulated cables are not accessible (i.e.,

cannot be viewed easily without the opening of metal covers).

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 3

cracking, melting, swelling, or surface contamination.

Robinson Document AD-EG-RNP-1615, Cable Aging Management Program, Revision 0, and AD-EG-ALL-1615, Cable Aging Management Program-Implementation, Revision 5 states: Accessible: Capable of being reached quickly for operation, renewal, or inspection, without requiring those to whom ready access is requisite to climb over or remove obstacles or to resort to portable ladders, etc. Cables and connections that can be approached and viewed easily without the opening of junction boxes or control panels are considered accessible.

Robinson SLRA Section 3.6.2.2.2 states: Except for the short security-crossing length, the top metal covers are removable to allow access to the insulated cables and their supports.

The staff notes that the cable bus insulated cables cannot be accessed without removing the top metal covers and, therefore, would not be accessible according to AD-EG-RNP-1615.

2 3.6.2.2.2, B2.1.37 B -

1066, B

- 222 Robinson SLRA Section 3.6.2.2.2 states the aging effects of Aging Management Review (AMR) 3.6.1-029 and AMR 3.6.1-031 will be managed by Robinson AMP B2.1.37 and AMP B2.1.34, respectively, that will be consistent with the NUREG 2191 AMP XI.E1 and AMP XI.S6 with enhancements.

SRP-SLR states: Therefore, the GALL-SLR Report recommends cable bus aging mechanisms and effects be evaluated as a plant-specific further evaluation...

Acceptance criteria are described in Branch Technical Position (BTP) RLSB-1 (Appendix A.1 of this SRP-SLR). In addition, SRP-SLR recommends that FSAR supplements be provided for each AMP.

Provide the cable bus insulated cables in the B2.1.37 to ensure that B2.1.37 satisfies SRP-SLR A.1.2.3.1 for cable bus.

Also, identify the cable bus in the FSAR supplement for B2.1.37 to satisfy the SRP-SLR.

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 4

SRP-SLR Appendix A.1, Subsection A.1.2.3.1, Scope of Program, states: The specific program necessary for SLR should be identified. The scope of the program should include the specific SCs, the aging of which the program manages.

The staff notes that cable bus is a specific electrical commodity that is separated from the insulated cables commodity covered by Robinson AMP B2.1.37.

Monitoring of Neutron-Absorbing Materials Other Than Boraflex Question Number SLRA Section SLRA Page Background / Issue Discussion Question / Request 1

Table 3.3.1 and Table B1-1 3-353 and B-9 SLRA Table 3.3.1 states that item 3.3.1-102 is not applicable because Robinson has no Boral, boron steel or other material spent fuel storage racks.

However, in Table B1-1 it states that the Monitoring of Neutron-Absorbing Materials Other Than Boraflex program is not applicable because it is not applicable to a pressurized water reactor (PWR). The inconsistency between the language used in Table 3.3.1 and Table B1-1 is unclear to the staff as the Monitoring of Neutron-Absorbing Materials Other Than Boraflex program is applicable to PWR plants that credit these materials for reactivity control.

Please clarify whether the Monitoring of Neutron-Absorbing Materials Other Than Boraflex program is not applicable because these materials are not used at Robinson as stated in Table 3.3.1 or if it is because the Monitoring of Neutron-Absorbing Materials Other Than Boraflex program is not applicable to PWRs as stated in Table B1-1.

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 5

Boraflex Monitoring Question Number SLRA Section SLRA Page Background / Issue Discussion Question / Request 1

Table 3.3.1 and Table B1-1 3-339 and B-8 In SLRA Table 3.3.1 it states that item 3.3.1-051 is not applicable because Boraflex is not credited for reactivity control in the Robinson spent fuel pool. However, in Table B1-1 it states that the Boraflex Monitoring program is not applicable because it is not applicable to a PWR. The inconsistency between the language used in Table 3.3.1 and Table B1-1 is unclear to the staff as the Boraflex Monitoring program is applicable to PWR plants that credit Boraflex for reactivity control.

Please clarify whether the Boraflex Monitoring program is not applicable because it is not credited for reactivity control as stated in Table 3.3.1 or if it is because the Boraflex Monitoring program is not applicable to PWRs as stated in Table B1-1.

Stainless Steel, Nickel, and Aluminum Alloy Further Evaluations Question Number SLRA Section SLRA Page Background / Issue Discussion Question / Request 1

3.2.2.2.2, 3.2.2.2.4, 3.3.2.2.3, 3.3.2.2.4, 3.3.2.2.8, 3.3.2.2.10, 3.4.2.2.2, 3.4.2.2.3, 3.4.2.2.7, 3.4.2.2.9, B.2.1.28 Many Six of the further evaluation (FE) sections referenced in this question address localized corrosion and stress corrosion cracking (SCC) for stainless steel and nickel alloys in air and condensation environments. These six sections refer to three cases of leakage apparently caused by chloride-induced outside-diameter pitting and SCC in stainless steel components in outdoor and uncontrolled indoor air, between 2009 and 2013. The information in the SLRA and made available in the e-Portal indicates the source of the chloride could not be determined.

In addition, the operating experience (OE) discussed in Please address the following:

a. Describe the examinations performed to determine the cause of the aluminum pipe cracking in the EDG return line, and what was concluded about the cause?
b. Clarify the approach to managing aging of aluminum alloys in uncontrolled indoor air, outdoor air, and condensation with respect to the possibility of chloride in these

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 6

SLRA Section B.2.1.28 for the Internal Coatings and Linings AMP describes a case of through-wall cracking in a polymer-lined aluminum alloy service water return line for the emergency diesel generators (EDGs). External cracking from contamination in the air was not identified as a contributor in the OE discussion but also not ruled out.

The description mentions a corrosive environment and rolling/pressing, which may be sources of high stress.

Based on the OE with stainless steel, the SLRA proposes periodic inspection programs for stainless steel for components exposed externally to air and condensation environments in the ESF, auxiliary, and steam and power conversion systems.

However, one-time inspection is proposed for aluminum alloys in outdoor or uncontrolled indoor air environments despite the potential presence of chloride and the possible SCC of aluminum piping. According to the FE guidance (e.g., 3.3.2.2.8), one-time inspection is appropriate when it is determined that SCC will not occur, but a periodic inspection program is appropriate for susceptible alloys if the environment potentially contains halides. The guidance also states that halide concentrations should be considered high enough to facilitate SCC of aluminum alloys in uncontrolled air, condensation, and outdoor air unless demonstrated otherwise.

Given the unidentified source of chloride causing SCC of stainless steel, the possible SCC of aluminum piping, and the FE guidance on selecting aging management programs for pitting corrosion, crevice corrosion, and SCC of stainless steels and aluminum alloys, it is unclear to the staff why one-time inspection is specified for aluminum alloys in uncontrolled indoor air, outdoor air, and environments and the potential SCC of the aluminum alloy return line.

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 7

condensation environments.

2 3.3.2.2.8, 3.3.2.2.10, Table 3.3.1, Table 3.3.2-32, Table 3.3.2-37 3-321, 3-324, 3-390, 3-640, 3-643, 3-658 For AMR Item 3.3.1-233, the FE discussion in SLRA Section 3.3.2.2.8 states that the in scope insulated aluminum piping, piping components, or tanks exposed to air or condensation in Auxiliary Systems are not susceptible to SCC. In addition, the discussion states that plant-specific notes are provided in the AMR tables for these components. However, item 3.3.1-233 is not used in any of the AMR tables.

The discussion in SLRA Table 3.3.1 states that item 3.3.1-233 is not applicable. It also states that the associated components are not formed of alloys susceptible to SCC.

However, there are plant-specific footnotes associated with AMR Item 3.3.1-245 stating the alloy is not susceptible to SCC. This item is for the same component category but applicable to loss of material rather than cracking. These footnotes are in SLRA Tables 3.3.2-36 and 3.3.2-37.

The information above suggests the following:

a. The designation Not Applicable for item 3.3.1-233 in Table 3.3.1 was not intended.
b. Item 3.3.1-233 was intended to be included in AMR Tables 3.3.2-36 and 3.3.2-37, with footnotes indicating the alloy is not susceptible.

The footnotes in Tables 3.3.2-36 and 3.3.2-37 associated with AMR Item 3.3.2-245 for loss of material were meant to be associated with item 3.3.1-233 for cracking.

Please clarify the aging management plans for SCC and loss of material for aluminum components associated with AMR items 3.3.1-233 and 3.3.1-245.

3 Table 3.3.2-18, 3-533, 3-319, AMR Item 3.3.1-234 addresses loss of material for aluminum piping, piping components, and tanks exposed to Please clarify the aging management plans and plant-specific note for loss of material and

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 8

3.3.2.2.8, 3.3.2.2.10 3-324 air and condensation. SLRA Table 3.3.2-18 has two instances of AMR Item 3.3.1-234 with plant-specific note 2 that states the material is not susceptible to SCC.

(Aluminum damper housings exposed to indoor uncontrolled air.) It appears the footnote should instead be associated with entries in Table 3.3.2-18 related to cracking that were not included. (Item 3.3.1-189?)

cracking of aluminum damper housings exposed to air and condensation in SLRA Table 3.3.2-18.

4 Table 3.3.2-36, Table 3.3.2-37 3-640, 3-641, 3-658 SLRA Tables 3.3.2-36 and 3.3.2-37 cite AMR Item 3.3.1-245 for insulated aluminum with internal coating/lining piping (AMR IDs 1091 and 6853) and insulated aluminum piping (AMR ID 3430) exposed externally to indoor uncontrolled air or outdoor air. Plant-specific notes 9 (SLRA Table 3.3.2-36) and 3 (SLRA Table 3.3.2-37) are cited for these items.

SLRA Tables 3.3.2-36 and 3.3.2-37 also cite AMR Item 3.3.1-248 (no aging effects or AMP) for insulated aluminum with internal coating/lining piping (AMR ID 1154) and insulated aluminum piping (AMR ID 3337) exposed externally to air with borated water leakage. Neither plant-specific note 9 (SLRA Table 3.3.2-36) nor 3 (SLRA Table 3.3.2-37) are cited for these items.

Please confirm the staffs understanding that AMR IDs 1091, 6853, and 1154 in SLRA Table 3.3.2-36; and AMR IDs 3430 and 3337 in SLRA Table 3.3.2-37 address the same components. Meaning the insulated aluminum with internal coating/lining piping and insulated aluminum piping exposed externally to indoor uncontrolled air or outdoor air may also be exposed to air with borated water leakage, therefore, AMR Item 3.3.1-248 was also cited.

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 9

Recurring Internal Corrosion Question Number SLRA Section SLRA Page Background / Issue Discussion Question / Request 1

3.2.2.2.7 466 The SLRA and the Fire Water basis document state that between January 2016 and December 2020, several instances of corrosion were identified. Further it states that these internal corrosion instances were small and non-recurring. Additionally, AR 00726507 had two pinhole water leaks in the Fire Water system.

1. Please identify how many instances of internal corrosion were identified and on what system.
2. Were the leaks in AR 00726507 caused by internal corrosion?

2 AR 02143300 his AR discusses a leak in the fire pump system in 2017. There is a mention of a history of similar problems in 2010 that caused a replacement due to pinholes.

What was the cause of this leak?

3 3.2.2.2.7,3.3.2.2.7,3.4.2.2.6 The staff requested ARs that the applicant used to determine there was no recurring internal corrosion. The applicant provided ARs AR02062956, AR02549950, AR02493460, and AR02495952. Additionally, the e-Portal has a key word search list document titled OE Data from New or Different Aging Effect Review with approximately 600 operating experience summaries sorted with key words.

ARs 02549950 and 02495952 are not on the OE Data from New or Different Aging Effect Review document. The staff would like to know how these two ARs were assessed and why they were not a part of the 600 screened ARs.

4 AR 02214981 This AR discusses a through-wall leak the 90-degree elbow. There is no mention of analysis of what caused the through wall.

What was the cause of the through-wall leak?

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 10 5

AR 02276562 AR for another leak at a 90-degree elbow. It was recommended piping was replaced.

3. What was the cause of the leak?
4. Was the removed piping evaluated?

6 3.2.2.2.7,3.3.2.2.7,3.4.2.2.6 Previous applicants have interpreted recurring internal corrosion to mean the recurrence occurred at the same exact spot in the system.

This interpretation is not the intent of the staffs position; however, the staff accepted the evaluation because the applicant assumed they had recurring internal corrosion (RIC) and were managing it regardless.

Is RIC being interpreted to mean the exact spot in the system?

Irradiation - Structural Question Number SLRA Section SLRA Page Background / Issue Discussion Question / Request 1

3.5.2.2.2.6 3-917 The SLRA states: The model geometry used in the transport calculations is based on that described in WCAP-18751-NP, Analysis of Ex-Vessel Neutron Dosimetry from H.B Robinson Unit 2 - Cycle 32 with expansion of the model geometry to facilitate explicit modeling of the limiting (highest fluence) inlet nozzle and outlet nozzle and the limiting reactor vessel (RV) support and surrounding concrete.

Show the two models and discuss to what extent the additions to the transport calculations model (expansion of the model geometry) used in WCAP-18751-NP augmented/reduced the calculated fluence/gamma dose at the BSW concrete and RV steel support structural steel assembly.

2 3.5.2.2.2.6 3-918 The SLRA states: NRC acceptance of this methodology is reported in the Final Safety Evaluation of the Point Beach Nuclear SLRA, Sections 3.5.2.2.2.6 and 3.5.2.2.2.7 Justify the uncertainty of 20% used in determining the fluence and gamma results for the steel liner

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 11 (ADAMS ML22140A127). The fluence and gamma results reported above were adjusted upwards to account for uncertainty (20% increase) for evaluation of the primary shield wall and the fracture analysis of the RV supports reported below.

Additionally, in previous SLRA reviews that employed the RAPTOR-M3G fluence methodology (WCAP-18124-NP-A and its supplement), certain structural steel components were stated as having a 25% uncertainty. Specifically, in the VC Summer SLRA, the uncertainty in the reactor pressure vessel (RPV) support structure steel dpa was 25% (page 3-194 to page 3-196 of the safety evaluation report (ML25021A228)) and in the Point Beach SLRA, the ring girder upper edge fluence uncertainty was 25% (page 3-237 to 3-238 of the Point Beach SLRA safety evaluation report (ML22140A127)).

It is not clear why RNP limits the radiation uncertainty to 20% in RV structural support and reactor cavity liner steel components.

plate, embedded steel anchorage, and the RPV steel support assembly.

3 3.5.2.2.2.6, Electronic reading room documents: CPL-CA120-TM-SA-000001, Revision 1 and 2 CPL-REAC-TM-AA-000001 Revision 1 3-917, 3-918 The SLRA states that the maximum projected RNP fluence (E > 0.1 MeV) and gamma dose at the inside surface of the PSW are 3.52E+19 n/cm2 and the maximum gamma dose is 1.05E+18 Gy [corrected to 1.05E+08 Gy] at 70 effective full-power years (EFPY),

both calculated using a 10% positive bias on relative power of peripheral and re-entrant corner fuel assemblies and an upwards adjusted uncertainty of 20% and that the region of exceedance extends from the ID of the primary shield wall approximately 3.74 inches into the 120-inch-thick primary shield wall at selected azimuthal locations.

The SLRA also states: The maximum fluence of the grout

c. Using construction drawing(s), show the azimuthal locations where radiation at the PSW exceeds the SRP-SLR limits of 1.0E+19 n/cm2 and 1.0E+08 Gy. Explain why the SLRA discusses the SRP-SLR radiation limits being exceeded at selected azimuthal locations when the analysis performed and discussed in CPL-CA120-

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 12 under the RPV support baseplates at 70 EFPY is projected to exceed the NUREG-2192 guidance threshold (1.00E+19 n/cm2).

The maximum fluence is projected to be 1.30E+19 n/cm2 (E>0.1 MeV, with 10% positive bias and adjusted for 20%

analytical uncertainty) at Core-Facing mid edge of support baseplates. However, the maximum fluence is projected to be 6.56E+18 n/cm2, which is less than the NUREG-2192 guidance threshold, at support baseplates corners.

Figures 2 and 4, of electronic reading room reference CPL-CA120-TM-SA-000001, Revision 1 and 2 show the estimated depth of neutron fluence and gamma dose exceedance to be for both 3.74 inches and assumed to include both the grout and concrete.

Electronic reading room reference 5.36, CPL-CA120-TM-SA-000001, Revision 2 also states that the depth of 3.74 inches does not include the small portion of the bioshield facing the ex-core instrumentation well. At this location scattering effects drive the exceedance depth beyond 3.74 inches (9.50 cm) radially at the face of the instrumentation well. However, this is the surface of the well face where the horizontal reinforcement bends back into the concrete mass and therefore a depth at which the vertical reinforcement is located circumferentially away from the exceedance.

Radiation streams in a radial direction from the RV to the PSW. The staff notes that while the SLRA discusses regions of radiation exposure exceeding the SRP-SLR limits of 1.0E+19 n/cm2 and 1.0E+08 Gy, for neutron fluence and gamma dose respectively at selected azimuthal locations, the referenced above CPL-CA120-TM-SA-000001, Revision 1 and Revision 2 do not TM-SA-000001, Revision 2 does not differentiate where they are exceeded.

d. Include in the discussion the reason why azimuthal position 50° (Instrument well edge) does not account for exceedance of SRP-SLR limits beyond 3.74 inches despite the quote in CPL-CA120-TM-SA-000001.
e. Clarify how the SRP-SLR gamma dose limits are bounded by the fluence at 3.74 inches, especially at the 4° azimuth, as shown in Figures 2 and 5 of CPL-CA120-TM-SA-000001, Revisions 1 and 2.
f. Clarify the depth of penetration of the neutron fluence and gamma dose at the baseplate grouting as shown in Figure 4 of electronic reading room reference CPL-CA120-TM-SA-00000-1, Revisions 1 and
2.

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 13 differentiate between affected and unaffected areas.

Instead, their Figure 5 confirms that portion of the RV supporting PSW concrete, grout and steel support assemblage to be subject to radiation. It also discusses areas of further radiation exceedance, which is not identified in Figure 5-5 of e-Portal reference CPL-REAC-TM-AA-000001 Revision 1, at azimuthal position 50o (Instrument well edge). It is not clear why the SLRA and the CPL-CA120-TM-SA-000001, Revisions 1 and 2, and CPL-REAC-TM-AA-000001 Revision 1 differ in certain aspects of PSW and supports radiation damage.

4 Electronic reading room document: CPL-REAC-TM-AA-000001, Rev. 1 53 CPL-REAC-TM-AA-000001, Rev. 1 (Page 53 of 62), dated February 8, 2023, states:

The location of maximum fluence occurred at 34 cm above the core midplane. With 10% positive bias applied to the peripheral and re-entrant fuel assembly relative powers, the volume of concrete with fast (E > 0.1 MeV) neutron fluence of 1x1019 neutrons/cm2 or higher was 377,000 cm3 for the quadrant.

Discuss how the maximum fluence does not materialize at core mid plane but about a foot above it. In discussion reference Figures 5-1 through 5-5 of CPL-REAC-TM-AA-000001, Revision 1.

5 3.5.2.2.2.6 3-913 922 SLRA Figure 3.5.2.2.2.6-1, Section through Reactor Containment Building, shows the general arrangement of SSC and RV at the reactor cavity. SLRA Figure 3.5.2.2.2.6-2, Reactor Vessel Support Configuration, shows a sketch of structural steel assemblage that serves as an RV support. SLRA Section 3.5.2.2.2.6 then, for the RV generated vertical, horizontal, and torsional loads identifies the load bearing components that are subject to ASME Section XI, 10 CFR 50.55a mandated IWF inspections and examinations and those promulgated by a) Using construction drawings briefly describe the SLRA identified RV steel supports, discuss how that assembly in its entirety integrates into the stainless steel lined PSW concrete including its reinforcement, how the RV anchors to the supports and reactor cavity wall to effectively transmit RV generated loads.

Include in the discussion the

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 14 GALL-SLR AMPs (e.g., XI.S3, XI.S6) guidance.

The SLRA figures noted above do not provide adequate clarity on the integration of the RV component supports and whether AMR table 2 items are assigned to those scoped in, in the SLRA.

secondary cavity (see SLRA page 3-915), its function and how it structurally integrates with the PSW.

b) Clarify what the weld buildup and reactor vessel nozzle pads are (see SLRA page 3-914) and identify these in relevant construction/fabrication drawings.

c) Clarify whether the RV thermal insulation and canal seal plate are included within the scope of SLR.

d) Clarify/identify the table 2 AMR line items that manage the effects of aging associated with radiation effects on the above described scoped in SSCs.

6 2.4.21 2-201 SLRA Section 2.4.21 states that the RV support structure consists of a circular box section ring girder, fabricated of carbon steel plates, and that the bottom flange of the girder is in continuous contact with a non-yielding concrete foundation. However, this ring girder is not described as part of the load path components described in SLRA Section 3.5.2.2.2.6.

It is also not clear how the ring girder integrates with the reactor support configuration/load path components and how the entire support assembly integrates into the PSW concrete.

a. Clarify why the circular box section ring girder is not included/considered in SLRA Section 3.5.2.2.2.6.
b. Identify the location of the circular box section ring girder and discuss how it is integrated in the RV steel support assembly. For its integration, please reference SLRA Figure 3.5.2.2.2.6-2 and/or relevant construction/fabrication DWGs.
c. Assuming it is scoped in, in the SLRA, identify the table 2 AMR line items that manage the effects of

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 15 aging associated with it.

7 Electronic reading room document: CPL-REAC-TM-AA-000001, Rev. 1 57-61 Figures 5-1 through 5-5 of CPL-REAC-TM-AA-000001, Rev. 1 show the depth to which radiation above the NUREG-2192 thresholds extends into the PSW. It is not clear whether the figures show just the aforementioned selected azimuthal locations where this radiation potentially could exceed the SRP-SLR limits and damage the reactor cavity structural concrete. It is not clear to what extent the effects of this radiation have been considered on the RV support anchorage and the PSW reinforcing steel, including its bonding to concrete.

a) Referencing Figures 5-1 through 5-5 of CPL-REAC-TM-AA-000001, Rev. 1, and using PSW concrete construction drawings, show the extent of estimated radiation exposure and potential damage to the PSW concrete, grout, steel reinforcement (hoop, vertical, ties), and anchor bolts at the SLRA-defined radiation areas/azimuthal locations.

b) Discuss potential aging effects associated with bonding of steel reinforcement to concrete (consider this with breakout question (BOQ) 9).

8

.5.2.2.2.6; WCAP-18939; Electronic reading room document: Reactor Building Calculation Book 3 3-916, 3-920, 3-923; vii; SLRA Section 3.5.2.2.2.6 states that the RNP Structures Monitoring Program (SMP) jurisdictional boundaries extend to include inspections of the Primary shield wallthe A-490 anchor bolts and A-36 anchor plate cast in concrete.

The SLRA also states: Based on the temperature distribution in the grillage assembly during full power operation, the top plate and support shoe have LSTs above 264°F and are not susceptible to irradiation embrittlement based on calculated ARTs using NUREG-1509, Figure 3-1.

The Executive Summary of WCAP-18939 states:

[F]racture mechanics analyses are performed to a) Clarify which AMP would examine the anchors/anchor bolts during the subsequent period of (SPEO). Would it be the SMP or potentially an ongoing limited in-scope ASME Section XI, Subsection IWF?

b) Discuss whether the ASTM A 490 bolts considered in the SLRA, WCAP-18939, and shown on Ebasco DWG 190561 were preloaded (pretensioned) or are bearing type connections as

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 16 investigate the impact of neutron embrittlement (radiation effects) on the RPV supports due to extended plant operation past 60 years.

[T]he material-specific fracture toughness is calculated for the support shoe, top plate, bottom plate, diaphragm plates, I-beams, and anchor bolt components considering the impact of neutron embrittlement at 80 calendar years (70 EFPY), to provide adequate margin in the RPV support structural integrity assessment.

The staff reviewed visual examination (VT-3) reports included in the 4th Ten-Year Inspection Relief Request (ML13178A006) which state that a remote video indicates that anchors/fasteners inspection results were satisfactory. The 5th Ten-Year Inservice Inspection Interval Relief request points out the limited in-scope examination ASME Section XI, Subsection IWF examinations that include the anchors.

There is a lack of clarity between the RNP SLRA and past relief requests that include VT-3 inspection reports as which RNP AMP inspects the anchors, the SMP or the ASME Section XI, Subsection IWF.

Given the complexity of the RV steel support assemblies, the multitude of bolts used for their construction, proximity to radiation source, and the prevailing 264°F temperature during reactor operation, it is also not clear whether the bolted connections would remain tightened, as loosening of the joints is an aging effect that could occur due to radiation and/or heating. It is not clear what Table 3.5.2 AMR line items would manage loosening of the bolted connections for these aging effects to the end of 80 calendar years (70 EFPY).

calculations in the electronic reading room Reactor Building Calculation Book 3, appear to indicate.

c) Clarify/identify the table 2 AMR line items that manage the effects of aging for loosening of RV support assembly bolts due to radiation and elevated temperatures/heating.

a) Considering the SLRA statement (top of SLRA page 3-923) that continued visual inspections of the RPV supports per ASME Section XI inspection plan is required, clarify/identify the specific table 2 AMR line items for these continued visual inspections of the RPV supports per ASME Section XI.

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 17 9

Electronic Reading Room Document 50 Attachment A -

Structural Engineering Review and Comparison of RX Vessel Support Material Condition; AR 00399274; AR 00398950; OE Data from New or Different Aging Effect Review 1-10; 66; 1; 71 Audited Attachment A - Structural Engineering Review and Comparison of RX Vessel Support Material Condition, Report discusses boric acid leakage over time on the A, B, C reactor vessel supports. Of particular interest are RO-26 (2010) when standing water was present during the examination of loop A. The report states that to eliminate leakage a new cavity seal was applied during RO-28, (2013). However, leakage was rediscovered during RO-30 and boric acid on A, B, C RV supports during RO-32 cavity inspections.

AR (NCR) 399274 for Boric Acid Corrosion Control Program Evaluation also provides an account and extent of the boric acid leakage but notes that leakage was not considered a pressure boundary or joint integrity leakage which require subsequent monitoring. AR (NCR) 398950 discusses actions taken including acoustic leak and visual inspections on 05/28/2010 via an underwater camera.

Posted summary of AR 02452522 discusses active leakage from the reactor cavity area down the outside of the concrete shield wall from 11/25/2022 to 12/8/2022.

The AR states that the leakage source is believed to be coming from the Sealed Table Room above. It also states that leakage seen in conjunction with the known leakage rate of the reactor cavity, a significant effort will be required for boric acid cleaning.

Although the said Report states that normal support ventilation and surrounding air temperature would evaporate the cavity water during normal plant operation, it is not clear what is the temporal and spatial extent of leakage of borated water in the reactor cavity area and on the PSW concrete particularly with the added observation of AR 02452522.

a) Discuss Refueling Canal and/or Sealed Table Room boric acid spillage/leakage current containment efforts and RV cavity area cleanup.

b) Are there any stains manifested on the visible surfaces of the PSW or reason to believe that boric acid may have infiltrated the concrete potentially causing rebar corrosion?

c) Has there been an allowance for potential loss of material/corrosion considered in SLR Table 3.5.2.2.2.6 SLR analyses/evaluations (see also BOQ 7).

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 18 Although it is apparent that RNP addresses the leakage, the staff could not find whether there is a record of the extent of the spillage on PSW concrete. It is not clear whether such leakage, overtime, has infiltrated the PSW concrete potentially affecting its reinforcement and its bonding to concrete, which could additionally be challenged by radiation effects during the SPEO (consider also BOQ 7).

10 3.5.2.2.2.6; Reactor Support Temperature Following Loss of HVH-6a and B; Electric Power Research Institute (EPRI), Report 3002018400, Revision 1

3-915, 3-920; 27; 2-2 12 The SLRA states that the concrete below the bottom plate remains at or below 150°F. It references UFSAR Figures 3.8.3-1 and 3.8.3-2 and states that at full powerthe peak concrete temperature within the primary shield wall remains below 150°F (Case I at 140.3°F) and includes gamma heating.

The SLRA also states that the top plate and support shoe have LSTs above 264°F. Ebasco DWG G-190561, and Pittsburgh Bridge and Iron Works, DWG 53790-01421, 53790-01421 (both Revision 1) show proximity of the anchor bolts to the shoe. RNP Calculation Reactor Support Temperature Following Loss of HVH-6a and B discusses how embedded anchors bolts exposed to elevated RV cavity temperatures could also affect the temperature within the concrete.

EPRI, Report 3002018400, Revision 1, 2020 Update to Irradiation of Concrete Guidance, referenced in SLR-RNP-FERR Revision 2 and in CPL-CA120-TM-SA-000001, Revision 1 and 2, shows that within the RV cavity the dependance of PSW concrete temperature to air flow velocity. It shows that for a typical RV cavity temperature of 150oF the temperature within the concrete is greater than that in the cavity.

Discuss how RNP concluded that its PSW concrete particularly around RV anchorage has a temperature of 140.3°F at 70 EFPY.

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 19 It is not clear how a temperature of 264oF at the top plate drops to 150°F at top of concrete below the bottom plate and subsequently to 140.3°F within the PSW. It is not clear what methodology RNP used to conclude that the PSW concrete temperature will be less than the RV cavity temperature when the recent EPRI analytical effort demonstrates otherwise.

11 3.5.2.2.2.6 3-915 The SLRA states:

The radial temperature distribution within the 10 ft thick primary shield wall adjacent to the core at full power is reported in the Robinson UFSAR Figure 3.8.3-1 and UFSAR Figure 3.8.3-2, which demonstrate that peak concrete temperature within the primary shield wall remains below 150°F (Case I at 140.3°F). The UFSAR analysis includes gamma heating of the primary shield wall.

A review of the UFSAR Figure 3.8.3-1 confirms that the internal PSW concrete temperature peaks out at about 140oF. The staff, however, could not locate where in the UFSAR there is a discussion on the contribution of the gamma dose to the SLRA stated temperature of 140.3°F.

Discuss to what extent the estimated 1.05E+08 Gy gamma dose at 80 years of reactor operation has been factored into the SLRA reported temperature of 140.3°F as extracted from UFSAR Revision 19, Figure 3.8.3-1.

12 3.5.2.2.2.6; 2.4.6; 3.5.2.1.21; 3-916; 2-179; 3-892 SLRA Section 3.5.2.2.2.6 subtitled Jurisdictional Boundaries for Inspections, defines inspections boundaries and states:

Grillage assembly including grout below the bottom plate and all support items above the grout: ASME Section XI, Subsection IWF, Examination Category F-A.

SLRA Section 2.4.6, NSSS Supports, confirms that the evaluation boundaries for NSSS supports include grout for a) Clarify and confirm whether grout inspections and examinations that are following the ASME Code Section XI, Subsection IWF inspections and examinations schedule during the SPEO are currently integrated with those of the ASME Code Section XI, Subsection IWF AMP B2.1.31 procedures and

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 20 ASME Class 1 piping and component supports. While SLRA Section 3.5.2.1.21 NSSS Supports, states that the NSSS supports are constructed of materials to include grout.

The staff notes that the ASME Code Section XI, Subsection IWF-1300, Support Examination Boundaries, state that [t]he boundary of an integral support (C) connected to a building structure (E) is the surface of the building structure, while IWF-1100 and -1210 explicitly define the scope and extent of Subsection IWF examinations for Class 1, 2, 3 and MC supports for piping and other than piping supports. The staff also notes that ACI 349.3R, Report on Evaluation and Repair of Existing Nuclear Safety-Related Concrete Structures, identifies grouts as a component of the nuclear safety-related concrete structures.

The effects of aging on cementitious materials, including grout, are managed by the SMP which implements the ACI 349.3R frequency of inspections of every 5 years, while those for ASME Code Section XI IWF are performed within a 10-year interval.

The staff notes that the SLRA includes age management of grout, in alignment with the GALL-SLR AMP XI.S6, with SLRA AMP B2.1.34 Structures Monitoring Program for its structural support function. Although Table 3.5.2-21 includes an AMR Item for grout referencing Table 3.5.1-055 for reduction in concrete anchor capacity, there is none for loss of strength/cracking.

To this end, the staff does not see an enhancement to the SLRA AMP B2.1.31 ASME Section XI, Subsection IWF, nor a table 2 item stating that the grout for the RV Class 1 structural supports would be age managed for reduction in performed accordingly.

b) Discuss the frequency of current and/or future inspections of the RV Class 1 structural steel supports grout and whether they follow the guidance of ACI 349.3R.

c) If the grout at the RV steel support assemblies is to be inspected by using SLRA AMP B2.1.31 and at the frequency designated by ACI 349.3R, provide the appropriate enhancement, a corresponding commitment, and an appropriate table 2 AMR Item or show that there is one.

d) If the grout is to be age managed with SLRA AMP B2.1.34, provide an appropriate table 2 AMR Item or show that there is one.

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 21 strength by the SLRA AMP B2.1.31.

It is not clear whether RNP has procedures in place integrating aging management and inspection of the RV Class 1 structural steel support grout for cracking/loss of strength due to radiation and any other aging mechanism following the recommendations and guidance of ACI 349.3R and other GALL-SLR suggested guidance with those of IWF.

13 3.5.2.2.2.6 3-915 The SLRA states that a 1 3/8-inch grout pad below the grillage assembly bottom plates is used to interface with the top of the concrete primary shield wall. The SLRA also states that the region of fluence exceedance extends from the ID of the primary shield wall approximately 3.74 inches into the 120-inch-thick primary shield wall at selected azimuthal locations. However, the SLRA does not discuss the region of fluence exceedance for the grout.

Structural grouting is an integral part of equipment support to the concrete foundation. Assuming that a typical non-shrink cementitious grout, a mix of hydraulic cement and fine aggregate, was applied to the concrete to transfer the RNP RV loads, the bottom of each steel support plate should be in full contact through a grout pack with the concrete surface.

It is not clear what the contents of the grout mix are. Its cement and fine aggregate mineralogical composition exposed to an aggressive environment (e.g., radiation, excessive temperatures) could potentially result in loss of strength and volumetric/dimensional changes (RIVE, shrinkage) for portion of the grout exposed to radiation at 70 EFPY and elevated temperatures during reactor a) Clarify the region of fluence exceedance for the grout b) Describe the composition/mix of the 1 3/8-inch grout pad and discuss whether it was evaluated for shrinkage, loss of strength, and RIVE, and whether an appropriate table 2 AMR line item has been included for managing the resultant effects of aging (work the response in this BOQ by considering the background information in BOQ 14 as well).

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 22 operation.

14 3.5.2.2.2.6 3-918 The SLRA states that the [G]rout strength is conservatively assumed as 3,000 psi as concrete design strength. According to EPRI 3002018400, Figure 3-1, at the maximum fluence of 1.30E+19 n/cm2, the concrete compressive strength could be reduced by 2% to have 98% of design concrete strength. The 2% compressive strength decrease is very localized. According to the analysis of record, required baseplate sizes exist for normal and accident loads, considering a 2% reduction in compressive strength, the required baseplate sizes increase, but are still significantly less than the actual baseplate area. Therefore, there is no impact to the required baseplate area due to the 2% reduction in compressive strength.

The staff notes that the lower bound curve in Figure 3-1 of EPRI TR-3002018400 indicates that the compressive strength ratio of irradiated versus unirradiated concrete exposed to fluence of 1 to 2E19 n/cm2 is about 80 percent.

The staff also notes that that the test data used in Figure 3-1 of the EPRI TR-3002018400 are from widely varying temperatures, energy levels, and generally from small test specimens not reflective of LWR constructs and operating conditions. These observations were made in literature by Maruyama et. al (https://doi:10.3151/jact.15.440) and by Bruck (principal investigator for EPRI report) et. al (https://doi.org/10.1016/j.nucengdes.2019.04.02).

The journal articles also discuss the effects of heat, drying shrinkage, and radiation on the strength of cementitious materials. When considering the effects of cavity temperature and radiation, the reduction of cementitious materials strength could be greater than that of EPRI TR-a) Considering the background provided in this and BOQ 13, clarify how it was determined that the reduction of grout strength as a cementitious material is only 2 percent.

b) In view of the 20 percent topical reduction of grout strength due to its exposure to radiation beyond the SRP-SLR limits, state whether adequate margins exist for the assembly base plate and grout to sustain all RV applied loads so they can meet their intended function to the end of 70 EFPY and that no additional aging management for the grout is required.

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 23 3002018400 Figure 3-1.

It is not clear how the 2 percent reduction in grout compressive strength was concluded. It is not clear what the margin on the required base plate size would be when the calculated reduction of grout strength is at least 20 percent and that of concrete exposed to higher fluence, even higher reduction.

15 3.5.2.2.2.6; Electronic reading room document: Reactor Building Calculation Book 3 3-918 The SLRA states: The maximum compression stresses on grout are located at the corners of Reactor Vessel Support baseplates. Utilizing liner interpolation, the compression stresses at core-facing mid edge of Reactor Vessel Support baseplates, located at 5/8 from the inside face of the Primary Shield Wall, is approximately 75% of the maximum compression stresses at the corners of the base plates. Therefore, stresses at the core-facing mid edge location are less than the reduced 98% of design strength and is acceptable. Because there is no neutron fluence affect at corners of RV support base plates, the reduced 98% designed concrete grout strength at core-facing mid edge of Reactor Vessel Support base plates has no detrimental effects on the design.

The staff reviewed the electronic reading room document titled Reactor Building Calculation Book 3, CPL Reactor Vessel Support and noted it contains the sizing of the support base plates to normal and accident load conditions. The staff also noted RNPs comment on AISC allowable cementitious material bearing capacity, that for a 3,000-psi compressive strength concrete AISC 1.5.5 limits the allowable bearing stress to 1125 psi. However, the staff could not align with the RNP conclusion that the stresses at mid edge, 5/8 from the inside face of the PSW are at 75 percent of the maximum compressive stresses a) Clarify what is meant by liner interpolation.

b) Explain how it was determined that the base plate compressive stresses at mid edge and 5/8 from the inside face of the PSW are at 75 percent of the maximum compressive stresses at the corners of the base plates and less that the AISC allowable of 1,125 psi.

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 24 at the corners of the base plates.

The staff notes that a 20 percent reduction of the allowable grout strength capacity, as discussed by the staff in BOQ 14, could potentially affect base plate stability, structural integrity of the supports, and hence destabilize the RV at 70 EFPY.

16 3.5.2.2.2.6 3-919 The SLRA states: When considering RIVE of the primary shield wall concrete, an approximate 4% localized volumetric swelling within 3.75 inches is estimated based on EPRI TR 30020117[10] at a fluence of 3.52E19 n/cm2.

The 2.5-inch air gap between the outside of the insulation and the inner diameter of the shield wall is estimated to be reduced by approximately 0.15 inches. This reduction in air gap will have a negligible effect on the 12,000 CFM air flow supplied by the fan.

Although a staff review of the SLRA referenced above EPRI report dated May 2018, confirms that for the fluence of 3.52E19 n/cm2 an approximate swelling of 4 percent could occur, the staff notes that the derived swelling percentage is limited to concrete mixes having carbonate (limestone) aggregates. The 2020 updated guidance for RIVE evaluation discussed in EPRI TR 3002018400, 2020 Update to Irradiation of Concrete Guidance, dated September 2020, elevates the volumetric swelling for quartzite type aggregates to about 18 percent.

It is not clear what type of aggregate RNP has used in its PSW concrete mix. An 18 percent aggregate swelling to a fluence exposure of 3.52E19 n/cm2 could potentially reduce the 2.5 inches RV cavity airgap up to 1/2 inch at 70 EFPY. Such a reduction of airgap space would restrict the airflow at the RV steel support assembly, while increasing Clarify and confirm that RNP concrete mix had carbonate/limestone aggregates which resulted in insignificant swelling and airgap reduction of 0.15 inches OR An up to 1/2 inch reduction in the 2.5 inches airgap due to inclusion of quartz type aggregates in the concrete mix would not affect the RV cavity airflow, thus maintaining the PSW concrete temperature within code allowables.

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 25 the PSW concrete internal temperature.

17 3.5.2.2.2.6; Electronic reading Room Documents:

Westinghouse: CPL-CA120-TM-SA-000001; Reactor Building Calculation Book 3 3-919; 10 SLRA Table 3.5.2.2.2.6-2, Primary Shield Wall Updated SLR Stress/ Code Stress Ratio presents data that shows that neglecting 3.75 inches from the inside face of the PSW is insignificant to its overall structural integrity. The table is also included in CPL-CA120-TM-SA-000001 H.

B. Robinson Unit 2 Subsequent License Renewal: Primary Shield Wall Concrete Assessment, Revisions 1 and 2. Those documents, further reference:

(a) Westinghouse: CPL-CA120-CN-SA-000001, Revision 0, H.B. Robinson Unit 2 Subsequent License Renewal:

Primary Shield Wall Concrete Assessment, dated March 2023; (b) Westinghouse: CPL-REAC-TMAA-AA-000005, Revision 0, Supplemental Concrete Exposure Data for H.B. Robinson Unit 2 Bioshield Concrete, dated February 2023; and (c) Westinghouse: CPL-REAC-TM-AA-000002, Revision 0, H.B. Robinson Unit 2 Subsequent License Renewal; Primary Shield Wall Concrete Gamma Heating Evaluation, dated December 2022.

Based on the statement in CPL-CA120-TM-SA-000001 Revision 1 and Revision 2, the staff assumes that [t]he PSW concrete evaluation is documented in reference (a) and the staff assumes that all SLR derived ratios in Table 3.5.2.2.2.6-2 two Revisions of the The staff also assumes that the analysis of record (AOR)

Stress/Code Stress Ratio calculations are based on Ebasco Reactor Building Calculation Book 3. However, a) Confirm that the SLR analysis summarized in SLRA Table 3.5.2.2.2.6-2 is described in Westinghouse reference (a). Briefly share the content of each of the refenced Westinghouse reports putting an emphasis on Report (a).

b) Using construction drawings indicate areas of the PSW concrete and reinforcing steel that would experience the SLRA Table 3.5.2.2.2.6-2 listed AOR and SLR Stress/Code Stress ratios.

Describe the methodologies used (hand calculations, stress/strength design) to derive the SLR Stress/Code Stress Ratio values in SLRA Table 3.5.2.2.2.6-2.

c) Discuss differences and the level of detail involved in the AOR and SLR analyses that would allow a head-to-head comparison between the two and the acceptance of the 6 percent margin in estimation of the required horizontal reinforcement.

Consider BOQ 28 (b) in the discussion.

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 26 there is a lack of clarity whether the location/areas, conditions, and methodologies used for their development are the same as those used for those for SLR that would allow a head-to-head comparison and extraction of potential margins.

18 3.5.2.2.2.6 3-918 SLRA states approximately that 3.75 of the PSW concrete exceeds the neutron and gamma dose SRP-SLR thresholds at 70 EFPY. Therefore, the SLRA neglects 3.75 of the PSW concrete inner cavity when calculating the concrete structural capacity.

Although SLRA Table 3.5.2.2.2.6-2 summarizes the stress/code stress ratios for concrete and reinforcement stresses, the SLRA does not discuss the impacts to the anchor bolt capacity (potential PSW concrete side breakout and block pullout) due to the reduced concrete cover.

Provide evaluation of PSW concrete strength for anchor bolt side breakout from lateral loads due to its reduced 3.75 side cover, as it is considered ineffective.

19 3.5.2.2.2.6; WCAP-18939-P 3-915 The SLRA and WCAP-18939-P, Revision 1 state that the support shoes are constructed from ASTM A 508 Class 2 steel. Ebasco DWG G-190551, Revision 9, states that the support shoes are fabricated from ASTM A 508 Class 4 steel. The two steels differ in chemical composition, material strengths (yield, tensile strengths) and performance characteristics (elongation, necking). The WCAP evaluates support shoe stresses and fracture toughness for the ASTM A 508 Class 2 steel.

It is not clear as to why the RNP SLRA and WCAP-18939 report a different shoe steel than the Ebasco DWG G-190551. It is also not clear whether there is conservatism in the WCAP-18939 report for the support shoe fracture toughness calculations.

a) Clarify why the WCAP-18939, Revision 1, Report evaluates the RV structural steel supports for fracture toughness for the ASTM A 508 Class 2 steel in lieu of the ASTM A 508 Class 4 steel shown on Ebasco DWG G-190551, Revision 9 General Notes.

b) Discuss advantages and/or conservatisms gained, if any, when using ASTM A508 Class 2 in the WCAP-18939 reported calculations.

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 27 20 3.5.2.2.2.6 3-915; 3-917 Regarding the support shoe, the first paragraph on this page states that thermal growth of the reactor vessel is allowed by permitting radial sliding on graphitic steel shims that were coated with a dry film lubricant (Molykote Type Z).

Graphitic steel is understood by the staff to be a type of steel which contains graphite particles to facilitate radial expansion. The NRC staff in prior SLRA reviews determined that graphite properties do not experience significant aging effects until neutron fluence exceeds 1 x 1019 n/cm2 based on E > 1.0 keV, which includes effects of both fast and slow neutrons.

It is not clear what is the fluence at the shims elevation level. It is also not clear how RNP determined that the graphitic shim steels could sustain the grout reported fluence (if applicable) without it degrading the intended function and performance of the shims during the SPEO.

a) Clarify what is the expected fluence and gamma dose at the graphitic steel shims at 70 EFPY.

b) If the expected fluence and gamma dose exceed the previously determined SLRA SE limits, describe its impact on maintaining the intended mechanical function (i.e.,

allowing thermal growth by permitting radial sliding on the graphitic steel shims) of the support shoes through the SPEO.

c) If the expected fluence and gamma dose exceeds the previously determined SLRA SE limits, discuss measures to be taken so that the graphitic shims are protected from the SLRA reported fluence and gamma dose.

21 3.5.2.2.2.6 3-915; 3-917 The SLRA states that graphitic machined shims were inserted and coated with Molykote Z, and the vessel was released back onto the shoes and installed shims.

Staff review of Molykote Z technical data sheet indicates that the product contains 95.0 to 99.0% molybdenum disulfide. GALL-SLR notes that molybdenum disulfide coatings on high strength bolting could precipitate SCC.

Staff review of literature, as noted in BOQ 20, indicates that the graphitic steel is a self-lubricating high strength steel and could experience a similar outcome in a conducive environment.

Clarify whether RNP monitors and age manages the molybdenum disulfide/Molykote Z coated graphitic machined shims for SCC. If not, discuss/clarify why the RNP Molykote Z coated shims are not subject to SCC.

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 28 The staff reviewed the SLRA and noted that the plant refrains from using molybdenum disulfide in high strength bolting applications. The staff also reviewed SLR-RNP-FERR-0500, Revision 2, Containments, Structures, and Component Supports, which is the FE 3.5.2.2.2.6 basis document and noted that there was no discussion of past use of molybdenum disulfide or Molykote coating and its monitoring for potential development of SCC of the graphitic shims.

It is not clear whether RNP monitored and managed any potential aging effects (e.g., SCC - stress, environment, and material could be conducive of SCC) stemming from the use of molybdenum disulfide/Molykote Z coating on the graphitic shims.

22 Electronic reading room documents: 35, 36, 40, 41, 43, WCAP-18939; ML24050A006 varies Audited Adverse Condition Investigation from AR 399274-19 for the RV support assembly steel components states that the loss of material could be up to 0.106 inches at cycle 27. The investigation discusses the corrosion for the WF 12X133 and 1-3/4 in diameter ASTM A-490 bolts to cycle 27 and states that to be insignificant.

However, the evaluation also states that if the cavity leakage that is causing the corrosion is left unabated for an extended number of years and outages, it is possible that the degradation could eventually reach a level that would encroach upon the structural integrity of the vessel support.

WCAP-18939-NP states that a corrosion allowance (i.e.,

material loss) of 0.046 inches (refueling outage (RFO)-33, Fall 2022) was applied in the fracture mechanics for each component cut path based on the current conditions of the RPV support structures. The staff notes that the WCAP-18939-NP corrosion estimate is based on the a) Clarify the basis of calculating the two different loss of material values for the RV structural steel assemblage.

b) Justify why the lower amount of material loss was selected.

c) Clarify the projected loss of material for the structural steel assemblage to the end of the SPEO, given the prevalent state of boric acid spillage.

d) Clarify/discuss/confirm that at each RFO the structural steel supports are cleaned so that no additional loss of material occurs than that currently existing.

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 29 audited EC 418725000_Attachment_C_-

_BACC_EVAL_of_RPV_Nozzle_Supports_ AR 2359059,

[NCR 2359059] (electronic reading room document 41),

which also recommends cleaning of the supports in RFO 33 and subsequent monitoring actions to be developed.

WCAP-18939-NP also states that the corrosion amount was considered in the stress intensity factor calculation by decreasing the wall thickness of the plate components.

It is not clear whether the supports are being kept clean so that the loss of material across all RV structural steel supports remains as calculated at 0.106 inches according to the AR 399274-19 or that of 0.046 inches as discussed in the aforementioned Attachment C to the end of the SPEO.

In reference to EC 418725, proprietary Attachment C, item

  1. 6, second paragraph, the staff noted a potential non-conservatism of the selected corrosion rate in later cycles in EC 418725, proprietary Attachment C (Item #9) with the cited corrosion rate chart.

Given the history of the RV supports brought forward to date in documents discussed above and further elaborated in RNP relief requests (e.g., ML24050A006), it is not clear as to the current status of the RV structural steel support assemblage, whether it would experience additional wastage to the end of the SPEO, and if so whether the use of NUREG-1509 is justified.

e) Justify that regardless of the cleanliness of the supports or loss of material experienced or projected to occur, the use of guidance in NUREG-1509 would still be an acceptable approach to evaluate the loss of fracture toughness of the RPV supports to the end of the SPEO.

f) Clarify if the corrosion amount was also considered in the stress intensity factor calculation for the bolting in the RPV support components.

g) In reference to EC 418725, proprietary Attachment C, clarify the effectiveness of the item #6, second paragraph in minimizing reactor cavity leakage.

h) Clarify the reasons for selecting the rate in EC 418725, proprietary Attachment C (Item #9), in later cycles, (please reference the cited corrosion rate chart).

i) When reactor cavity leakage happens in an outage, clarify whether this leakage is added to the accumulated leakage from the previous outages.

23 Electronic reading 5

Attachment A, Effects of Corrosion on Design Margin of Provide evaluation of the anchor

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 30 room document: EC 418725000 Support from RO-26 and Beyond, discusses the ASTM A490 bolting net allowable load after a degradation of the cross section and compares it against the design load.

It appears these anchor bolts are subject to a combined loading of tension and shear. It is unclear whether the reduced anchor bolt size under combined loading stresses still meets the allowable load limit.

bolts with the reduced cross-sectional area for combined loading (shear and tension).

24 3.5.2.2.2.6; Electronic reading room document: RNP-M/HVAC-1076 3-915; 5,6 The SLRA discusses the air flow through the reactor cavity in the following paragraph on page 3-915, Each support assembly receives approximately 3,000 CFM of air flow from the reactor cavity to ensure that the concrete below the bottom plate remains at or below 150°F. Air flow is from the reactor cavity annulus between the reactor vessel insulation and the primary shield wall, through each support assembly just below the RV nozzles, to the HVAC ductwork that extends through the primary shield wall, to the suction side of HVAC fans HVE-6A/6B (6B is a standby fan) and discharged to the secondary cavity.

HVE-6A and -6B fans are designated as Quality Class B or augmented quality at RNP; augmented quality exceeds those requirements for Non-Safety-Related Items, but do not meet the criteria requirements for Safety-Related Items. In the schematic below, air flow direction is from the front of the assembly to the back of the assembly. ASME Section XI, Subsection IWF (B2.1.31), VT-3 examinations are conducted by extending a remote camera through the ductwork to the back of the assembly.

Electronic reading room document RNP-M/HVAC-1076, Reactor Support Temperature Following Loss of HVH-6A and B. contains calculations of forced-air convection cooling of the reactor cavity. Page 6 of the document depicts the fans that provide forced-air cooling to the Clarify that the assumed loss of forced-air cooling scenarios discussed in number 2 on page 5 were used to evaluate the RV support temperature in e-Portal document RNP-M/HVAC-1076.

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 31 reactor cavity. It is not clear to the staff that the assumed loss of forced-air cooling scenarios that were evaluated in the document follows assumption number 2 on page 5 of the document, which states that either both HVH-6A and B fail or HVH-(A and B fail, but not all four fans).

25 3.5.2.2.2.6 3-919 The first paragraph of SLRA section titled Reactor Vessel Support Steel Evaluation (Irradiation Embrittlement) lists the anchor plates as one of the steel support items.

However, it is not clear what the neutron fluence levels are at the anchor plates and why the anchor plates are not listed in the fracture mechanics results in SLRA Table 3.5.2.2.2.6-3.

Clarify the neutron fluence at the anchor plates embedded in concrete and why the anchor plates were not included in the fracture mechanics summary results in SLRA Table 3.5.2.2.2.6-3.

26 3.5.2.2.2.6; Electronic reading room document: Ebasco Specification: H.R.

Robinson Unit No. 2, Structural Steel Equipment Supports, 700,000 kW Extension 3-920 SLRA 3.5.2.2.2.6 page 3-920 states that the original design of the RV support structural steel elements is in accordance with the AISC Manual of Steel Construction 6th Edition, 4th Revised Printing, 1967 and the Ebasco Design Specification. However, there is no mention of the initial fabrication quality controls for the RV structural steel elements specified in these documents (but they are mentioned in WCAP-18939-P). There is also no mention in the SLRA of whether there is any crack growth mechanisms present in the supports.

a) Clarify whether the initial fabrication quality controls for the RV structural steel elements that ensure that these steel elements (including their weldments) are free from rejectable defects and cracks after initial fabrication. (This must be clearly included in SLRA 3.5.2.2.2.6.)

b) Clarify also whether there are any crack growth mechanisms in the supports. (This must be clearly included in SLRA 3.5.2.2.2.6.)

27

.5.2.2.2.6; WCAP-18939-P 3-921; 4-3, 5-3, 5-4 SLRA page 3-921 discusses the fracture mechanics analysis for the RV steel support components. Proprietary WCAP-18939-P Revision 1 contains details of the determination of fracture toughness values and stress a) Clarify/discuss the determination of fracture toughness for the plates (Section 5.1.1.2) and I-beams (Section 5.1.1.3), with particular emphasis on the first

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 32 intensity factors for this analysis. The staff is not clear on the approach taken to determine fracture toughness for the plates and I-beams (pages 5-3 and 5-4 of WCAP-18939-P) and in the approach taken in the treatment of applied stress (page 4-3 of WCAP-18939-P) to calculate the stress intensity factors for the support shoe.

equation used in making the determination of each respective fracture toughness value.

b) Clarify/discuss the calculation of stress intensity factors, with particular emphasis on the approach taken in the treatment of applied stress for the support shoe.

28 3.5.2.2.2.6; Amendment 279 SE (ML24114A015) 3-919 921 SLRA page 3-921 states: The H.B. Robinson Unit 2 specific loading conditions (i.e., normal, upset, accident based on extended leak-before-break) are considered.

However, the results of the fracture mechanics analysis in SLRA Table 3.5.2.2.2.6-3 show loading conditions only for normal and accident loading conditions.

SLRA page 3-919 states that extended leak-before-break (eLBB) was considered in the calculation of the stress interaction and restated so in SLRA page 3-921 in the fracture mechanics analysis of the RV steel supports. The staff reviewed amendment 279 (ML24114A015) SE for the Robinson eLBB and the associated Duke amendment submittal, and needs confirmation whether the eLBB analyses that were performed were for the entire line analyzed (i.e., entire pressurizer surge line, entire residual heat removal line, entire accumulator line). The staff also needs clarification on the amount of reduction in pipe break loads impacting the RV supports due to consideration of the eLBB.

a) Clarify why the loading conditions in the fracture mechanics analysis of the RV steel support structures include only the normal and accident loading conditions, and not the upset loading condition.

b) Clarify the loading conditions used in the load capacity structural analysis, i.e., in the analysis that resulted in SLRA Table 3.5.2.2.2.6-2.

c) Confirm whether the eLBB analyses performed were for the entire line analyzed (i.e., entire pressurizer surge line, entire residual heat removal line, entire accumulator line).

d) Clarify the reduction in pipe break (i.e., accident) loads due to taking credit for eLBB.

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 33 Concrete Question Number SLRA Section SLRA Page Background / Issue Discussion Question /

Request 1

Section 3.5.2.2.2.1, item 1; Section 3.5.2.2.2.1, item 4 3-906; 3-906 AMR Item 3.5.1-042 addresses the aging effects of loss of material (spalling, scaling) and cracking due to freeze-thaw for Groups 1-3, 5, 7-9 concrete (inaccessible areas) exposed to air - outdoor and groundwater/soil environments.

AMR Item 3.5.1-047 addresses the aging effects of increase in porosity and permeability, loss of strength due to leaching of calcium hydroxide and carbonation for Groups 1-5, 7-9 concrete (inaccessible areas) exposed to water-flowing environment.

However, AMR Items 3.5.1-042 and 3.5.1-047 are not used for the concrete elements of the Reactor Auxiliary Building in SLRA Table 3.5.2-2.

Clarify if the aging effects of loss of material (spalling, scaling) and cracking due to freeze-thaw (AMR Item 3.5.1-042) and increase in porosity and permeability, loss of strength due to leaching of calcium hydroxide (AMR Item 3.5.1-047) are applicable to the concrete elements of the Reactor Auxiliary Building.

2 Section 3.5.2.2.2.1, item 3 3-906 AMR Item 3.5.1-044 addresses the aging effects of cracking and distortion due to increased stress levels from settlement for all groups of concrete structures. However, AMR Item 3.5.1-044 is not used for the concrete elements of the Reactor Containment Building in SLRA Table 3.5.2-1.

Clarify if the aging effects of cracking and distortion due to increased stress levels from settlement (AMR Item 3.5.1-044) are applicable to the concrete elements of the Reactor Containment Building.

3 Section 3.5.2.2.2.1, item 3 3-906 AMR Item 3.5.1-046 addresses the aging effect of reduction of foundation strength and cracking due to differential settlement and erosion of porous concrete subfoundation for Groups 1-5, 7-9 structures. However, GALL item III.A3.TP-31 (for Group 3 structures), instead of III.A6.TP-31 (for Group 6 structures), is used for Reservoir and Dam in SLRA Table 3.5.2-24.

Clarify if GALL item III.A6.TP-31 should be used instead of III.A3.TP-31 for Reservoir and Dam in SLRA Table 3.5.2-24.

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 34 Non-GALL AMR - Mechanical Components Question Number SLRA Section SLRA Page Background / Issue Discussion Question / Request 1

N/A N/A The OE provided to support the review of the Compressed Air Monitoring AMP includes AR02089154, Air Compressor Reliability Self-Assessment, which looked at ARs associated with the Instrument Air compressor. Section 2 of the self-assessment includes the following (page 2 of Attachment 2):

  • NCR 2093649 - PAC Dryer Relief Valve IA-3857 Sheared off (Jan-22-2017) is listed as a Maintenance Rule Functional Failure.
  • The event was determined to be a result of intergranular SCC cause by years of exposure to ammonia solution from cleaning solutions used during preventive maintenance (PM) on the dryer cooling coils. The PM was modified to clean the area with demineralized water after the work is complete.

The material that was exposed to ammonia and failed by intergranular SCC is not identified in the OE.

Please discuss the potential impact of this operating experience on license renewal in-scope components, including the material, the extent to which ammonia cleaning solutions may have affected other components, and the actions taken, or being taken, to address SCC in ammonia solutions for other components.

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 35 AUXILIARY SYSTEMS Question Number SLRA Section SLRA Page Background / Issue Discussion Question / Request 1

2.3.3.11 2-85 Table 2.3.3-11 of the SLRA excludes the following fire protection components from the scope of subsequent license renewal and from being subject to an AMR:

  • Clean agent fire suppression system storage bottle
  • Pressure regulator
  • Valve body

2 2.3.3.12 2-86 Table 2.3.3-12 of the SLRA excludes the following fire protection components from the scope of subsequent license renewal and from being subject to an AMR:

  • CO2 fire suppression system storage tank

3 2.3.3.13 2-87 Table 2.3.3-13 of the SLRA excludes the following fire protection components from the scope of subsequent license renewal and from being subject to an AMR:

  • CO2 fire suppression system storage tank

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 36

  • CO2 distribution manifold applicant provide justification for their exclusion.

4 2.3.3.17 2-93 Table 2.3.3-17 of the SLRA excludes the following fire protection components from the scope of subsequent license renewal and from being subject to an AMR:

  • Halon fire suppression system storage bottle
  • Pressure regulator

5 2.3.3.37 2-130 Table 2.3.3-37 of the SLRA excludes the following fire protection components from the scope of subsequent license renewal and from being subject to an AMR:

  • Filter housing
  • Standpipe riser
  • Seismic support for standpipes system piping
  • Fire hose station
  • Floor drains for firefighting water
  • Dike for oil spill confinement
  • Intake traveling screen/trash rack
  • Diesel-driven fire pump oil storage tank vent
  • Flame arrester
  • Passive components in diesel-driven fire pump engine, Heat exchanger (diesel fire water pump cooler) shell side components Verify whether the listed system/components are within the scope of subsequent 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 subsequent license renewal and not subject to an AMR, the staff requests that the applicant provide justification for their exclusion.

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 37

  • Heat exchanger (diesel fire pump water pump cooler) tubes
  • Diesel-driven fire pump engine muffler and silencer
  • Transformer oil collection basin
  • Transformer deluge/water spray system 6

2.3.3.4 131 Drawing RSLRD-5379-00685-001. Location D6 -

Piping to flange above CVC-300F - inconsistent with piping above CVC-300C and CVC-300J.

Piping above CVC-300F should be magenta (spatial) and blue line should be discontinued.

Confirm markup is correct around valve CVC-300F.

7 2.3.3.4 131 Drawing RSLRD-5379-00921-002. Location G7/G6/G5 - Piping marked spatial leading to WD-1876, WD-1873, and WD-1872, but the connecting piping is not marked spatial.

Confirm that the connecting piping described does not have to be annotated as in scope.

8 2.3.4.1 196 Drawing RSLRD-HBR2-08680. The piping upstream and downstream of the Gland Steam Condenser Exhausters is not annotated in scope (spatial). The piping is enveloped by components identified as spatial.

Confirm that the piping/components enveloped by components annotated as in scope does not have to be annotated as in scope.

9 2.3.3.15 131 Drawing RSLRD-00921-002. Multiple diaphragm valves upstream to drains are annotated as in scope. Upstream piping is only partially annotated to be in scope, up to the pipe junction, while the rest is not annotated as in scope, such as valves WD-1868 and WD-1869 in D2.

Confirm that the connecting piping described does not have to be annotated as in scope.

10 2.3.3.35 126 Drawing RSLRD-G-190200-003. Multiple lines Confirm that connecting piping between major

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 38 surrounding Station Air Receiver, Aftercooler &

Separator and Station Air Compressor not annotated in scope or partially annotated in scope (spatial). Piping is surrounded by in-scope components.

components and piping at least up to first isolation valve of Station Air receiver is not required to be in scope.

CONTAINMENTS, STRUCTURES, AND COMPONENT SUPPORTS Question Number SLRA Section SLRA Page Background / Issue Discussion Question / Request 1

2.4 2-162 Section 2.4 of the SLRA includes passive fire barriers in the Reactor Containment, Reactor Auxiliary, Fuel Handling, Radwaste, and Switchgear Buildings within the scope of subsequent license renewal and subject to an AMR. However, passive fire barriers in the Robinson power block structure (UFSAR Table 9.5.1-1), Control Building (fire area A18), Turbine Building (fire area G1),

Diesel Fuel Oil Storage (fire area G2), Intake Structure (fire area G3), Dedicated Shutdown Diesel Generator Enclosure (fire area G7), and Residual Heat Removal Pump Room (fire area H) are excluded from the scope of subsequent license renewal and an AMR.

Verify whether the listed power block structure passive fire barriers are within the scope of subsequent 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 subsequent license renewal and not subject to an AMR, the staff requests that the applicant provide justification for their exclusion.

2 2.4 2-197 Table 2.4.18, Miscellaneous Structural Commodities, of the SLRA excludes the following fire barrier commodities from the scope of subsequent license renewal and from being subject to an AMR:

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 39 wrap material)

  • Fire plug/fire hatches
  • Radiant energy heat shield
  • Fire retardant cable coatings justification for their exclusion.

ELECTRICAL COMPONENT GROUPS Question Number SLRA Section SLRA Page Background / Issue Discussion Question / Request 1

2.5 2-214 SLRA Section 2.3.3-37, Site Fire Protection System, states that fire detection systems are evaluated with Electrical and Instrumentation and Controls, SLRA Section 2.5. However, Section 2.5 of the SLRA excludes passive components in the area-wide and in-cabinet VEWFDS installed in the cable spreading room, main control board, safeguard cabinets, Hagan room cabinets, turbine supervisory cabinets, and rod control room cabinets from the scope of subsequent license renewal and from being subject to an AMR. Section 3.1.3.2, Very Early Warning Fire Detection Systems, (page 41) of the NFPA 805 safety evaluation report (ML16337A264), discusses VEWFDS.

Verify whether the passive components in VEWFDS are within the scope of subsequent 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 subsequent license renewal and not subject to an AMR, the staff requests that the applicant provide justification for their exclusion.

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 40 ASME XI - ISI (IWB,IWC,IWD)

Question Number SLRA Section SLRA Page Background / Issue Discussion Question / Request 1

3.1 3-52, 3.2.1-5 In SLRA Table 3.1.1, Item 3.1.1-034 which is associated with stainless steel, steel with stainless steel cladding pressurizer relief tank (tank shell and heads, flanges, nozzles) exposed to treated borated water >60 deg C(>140 def F), in the Discussion column, it is partly stated that these components are non-ASME. Robinson UFSAR (Rev. 27) Table 3.2.2-1 (3.2.2-2) list the component code requirements of the pressurizer relief tank as ASME Section III, Class C, and UFSAR Table 3.2.1-2 lists the pressurizer relief tank as Class II.

Please clarify if the Robinson pressurizer relief tank is or is not ASME Class component, and clarify if either the SLRA or the UFSAR has an error related to the ASME classification for this component.

Steam Generators Question Number SLRA Section SLRA Page Background / Issue Discussion Question / Request 1

The Steam Generators AMP Evaluation Report (SLR-RNP-AMPR-XI.M19) lists (page 5 of 59) the EPRI Steam Generator Guidelines referenced by NEI 97-06 that are used for steam generator inspections, personnel qualification and eddy current technique qualification. The bottom of page 5 also states:

"Whenever a revision to NEI 97-06 or its referenced EPRI Guidelines is issued (including interim guidance), the guidelines are adopted and implemented by the Duke Energy fleet, in accordance with the implementation letter, unless appropriate justification for a deviation has been provided."

In the INDUSTRY REFERENCES section (page 48 of 59), the Please clarify the version of the EPRI SG Program documents referenced by NEI 97-06, except for the water chemistry related guidelines, that are currently in use at Robinson. The staff notes that the EPRI "PWR Primary to Secondary Leak Guidelines" were listed on page 5 of 59 of the AMP Evaluation Report but were not included in the Section 7.2 Industry References

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 41 following document revisions are shown:

Reference 7.2.5, "Steam Generator Integrity Assessment Guidelines," Revision 3.

Reference 7.2.6, "Steam Generator Degradation Specific Management Flaw Handbook, Revision 1 Reference 7.2.7. "Steam Generator In Situ Pressure Test Guidelines," Revision 4.

Reference 7.2.8 "Pressurized Water Reactor Steam Generator Examination Guidelines, Revision 7 The staff notes that reference 7.2.8, "Pressurized Water Reactor Steam Generator Examination Guidelines, Revision 7 is referenced in NUREG-2192 Section 3.1.6, References. Each of the EPRI SG Guidelines, however, has been revised at least once since the revision listed in the AMP Evaluation Report.

Fire Protection Question Number SLRA Section SLRA Page Background / Issue Discussion Question / Request 1

3.5 3-971 AMR Item 3.3.1-060 in NUREG-2192 manages cracking and loss of material of concrete structural fire barriers by both the Fire Protection and SMPs.

SLRA Table 3.5.2-2 credits only the SMP for managing cracking and loss of material of concrete elements that have a fire barrier intended function.

Please discuss why the Fire Protection program was not also credited for managing cracking and loss of material of concrete elements that have a fire barrier intended function.

2 2.4, 3.5 2-166, 2-170, 3-956 SLRA Section 2.4.1 states, Curbs have been provided in Reactor Coolant Pump B and C bays to prevent an oil leak from spreading a fire.

Please discuss whether the fire barrier intended function should be applied to concrete elements in the Reactor Containment Building and cracking and

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 42 SLRA Tables 2.4.1 and 3.5.2-1 only cite a fire barrier intended function for cylinder walls.

Plant-specific note 1 to SLRA Table 3.5.2-1 states, Concrete elements include beams, columns, walls, slabs, curbs, foundations and pads within the interior or above-grade exterior of the Reactor Building.

loss of material, along with the SMP, should be managed by the Fire Protection program.

3 3.5, Appendix B

3-

1026, B-101 Section 4.1 of SLR-RNP-AMPR-XI.M26, Revision 000 (Fire Protection program basis document) states, The Fire Protection program manages loss of material and cracking for metallic materials and concrete. The program manages cracking/delamination, separation, and loss of sealing for nonmetallic materials and cementitious coatings. Hardening, loss of strength, and change in material properties for nonmetallic materials and cementitious coatings are managed by evidence of cracking/delamination, separation, and loss of sealing.

SLRA Table 3.5.2-18 appears to only credit the Structures Monitoring program for managing loss of sealing for elastomer, rubber, and other similar material penetration seals and seismic gap filler material. Loss of sealing is not cited as an applicable aging effect for cementitious coatings in SLRA Table 3.5.2-18. In addition, SLRA Section B2.1.15 does not identify loss of sealing as an applicable aging effect managed by the Fire Protection program.

The staff would like to note that the Fire Protection program manages loss of material for materials other than metallic materials and concrete as indicated in Please discuss whether the Fire Protection program should be cited in the SLRA for managing loss of sealing of nonmetallic materials and cementitious coatings with a fire barrier intended function.

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 43 SLRA Table 3.5.2-18.

4 Appendix B

B-103 The third OE example in SLRA Section B2.1.15 refers to grout being repaired (AR02304824).

The SLRA does not appear to include a specific aging management evaluation line item for grout with a fire barrier intended function.

Please discuss whether grout with a fire barrier intended function should be addressed in the SLRA.

If it is addressed by an existing AMR line item, please identify the applicable AMR line item.

5 Appendix B

B-102 SLRA Section B2.1.15 includes enhancements to the Parameters Monitored or Inspected (Element 3),

Detection of Aging Effects (Element 4), and Acceptance Criteria (Element 6) program elements related to visual inspection of fire dampers and external surfaces of the carbon dioxide, halon, and clean agent fire suppression systems.

The staff notes that the enhancement related to fire dampers only applies to elements 3 and 6. It is unclear why it does not also apply to Element 4 given that it indicates visual inspection of the fire dampers.

The staff notes that both enhancements do not appear to state what the acceptance criteria will be, even though they both apply to Element 6.

The staff notes that Section 4.6 of the Fire Protection program basis document states that the acceptance criteria for the periodic visual inspections of the external surfaces of the carbon dioxide, halon, and clean agent fire suppression systems will be no indications of excessive loss of material, which is consistent with Volume 2 of NUREG-2191. In addition, the Fire Protection program basis Please address the following:

5. Why does Element 4 not apply to the enhancement related to the visual inspections of fire dampers?
6. Why do the enhancements not state what the acceptance criteria will be given that Element 6 applies to both enhancements?

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 44 document states that acceptance criteria require that the fire dampers are functional.

The staff notes that the recommended acceptance criteria in Volume 2 of NUREG-2191 for fire dampers is no visual indications of cracks or corrosion of fire damper assemblies.

6 N/A N/A Section 7.4 of -693, Revision 10 is related to Fire Probabilistic Risk Assessment credited berms and pedestal drains.

The SLRA does not appear to include berms or pedestal drains with a fire barrier intended function.

Please discuss whether berms and/or pedestal drains with a fire barrier intended function should be addressed in the SLRA. If they are addressed by existing AMR line items, please identify the applicable AMR line items.

7 3.5 3-1028 Plant-specific note 1 to SLRA Table 3.5.2-18 states, Steel and stainless steel fasteners used to secure fire barrier wraps in place are evaluated as fire barriers - penetration seals component type.

The staff is unclear about the meaning of this plant-specific note given that penetration seals are elastomer, rubber, and other similar materials, not steel and stainless steel, and the plant-specific note is not associated with the penetration seals component types.

Please discuss the intent of plant-specific note 1 to SLRA Table 3.5.2-18.

8 N/A N/A On Page 3 of Attachment 1 to OST-693, Revision 10, there appears to be fire wall skirting in contact with gravel and concrete. In addition, the photograph representing an unacceptable overlap appears to show moisture at the interface between the skirting and concrete (and potentially between the skirting and gravel).

Please address the following:

7. Confirm that AMR ID 5480 in SLRA Table 3.5.2-18 addresses the skirting.
8. Discuss how the skirting in contact with gravel and concrete that appear to have the potential to be exposed to moisture were considered when determining applicable environments

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 45 Given that gravel and concrete are not identified as applicable environments for steel fire barriers, it is unclear how these configurations were considered in the SLRA.

The staff assumes AMR ID 5480 in SLRA Table 3.5.2-18 addresses the skirting.

and/or aging effects.

9 N/A N/A In the markup to Section 5.0 of OST-623, Revision 28, it states, Initiate a Nuclear Condition Report (NCR) for fire dampers that do not meet the acceptance criteria.

Please discuss whether the markup should refer to fire barrier penetration seals instead of fire dampers?

10 N/A N/A Section 1 of OST-623, Revision 28, states that the sample does not include Containment penetrations.

Please identify the procedure that covers the periodic inspections of penetrations in containment. In addition, please summarize the scope of the containment penetration inspections, frequency, acceptance criteria, and corrective actions.

Specifically, do they meet the recommendations in GALL-SLR Report AMP XI.M26 for penetration seals?

11 N/A N/A Neither the SLRA nor documents on the e-Portal appear to address gypsum.

Please discuss whether gypsum with a fire barrier intended function is used at Robinson and whether it should be addressed in the SLRA. If it is addressed by an existing AMR line item, please identify the applicable AMR line item.

Fire Water System Question Number SLRA Section SLRA Page Background / Issue Discussion Question / Request

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 46 1

3.3 3-655 SLRA Table 3.3.2-37 cites raw water (internal) and soil (external) environments for the ductile iron and ductile iron with internal coating/lining fire hydrants. It is unclear whether these fire hydrants are also exposed to an air environment.

The staff notes that AMR Item 3.3.1-063 addresses loss of material of steel fire hydrants exposed to outdoor air.

Please discuss whether the ductile iron and ductile iron with internal coating/lining fire hydrants are exposed to an air environment.

2 Appendix A,

Appendix B

A-16, A-58, B-104, B-104 SLRA Section A2.1.16 states, Testing or replacement of sprinklers that have been in place for 50 years is performed consistent with NFPA 25.

SLRA Table A6.0-1 and SLRA Section B2.1.16 include an enhancement to the Fire Water System program related to sprinkler heads being replaced or tested prior to 50 years in service consistent with Section 5.3.1 of the 2011 Edition of NFPA 25.

SLRA Section B2.1.16 also states, The Fire Water System aging management program will either replace sprinkler heads prior to 50 years in service or submit a representative sample of sprinkler heads for testing consistent with the 2011 Edition of NFPA 25, Standard for the Inspection, Testing and Maintenance of Water-Based Fire Protection Systems, Section 5.3.1. The timing for replacement or testing will be determined based on the date of the sprinkler system installation.

The staff noted that Section 7.5.4 in Revision 21 of FP-013 states, Ensure Sprinkler heads in service for 50 years in the sprinkler systems identified in Step 1 and Step 2 are replaced or representative samples Please discuss the following:

9. What is the intent of the enhancement in SLRA Sections A2.1.16 and B2.1.16 and SLRA Table A6.0-1 Section 7.5.4 given that the 50-year standard sprinkler replacement or testing frequency is discussed in Section 7.5.4 in Revision 21 of FP-013.
10. Will all replacement and testing of sprinklers be in accordance with all sub bullets of Section 5.3.1 of the 2011 Edition of NFPA 25?
11. If sprinkler replacement and testing will be in accordance with all sub bullets of Section 5.3.1 of the 2011 Edition of NFPA 25, then discuss whether the enhancement to the Fire Water System program should be updated to reflect that.

Confirm which option from Footnote 7 for GALL-SLR Report Table XI.M27-1 was selected.

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 47 shall be subjected to field service testing per NFPA 25 requirements. Changes to this section were not captured in the Revision Summary, therefore, it is unclear on the intent of the enhancement in SLRA Sections A2.1.16 and B2.1.16 and SLRA Table A6.0-

1.

The staff notes that Footnote 2 for GALL-SLR Report Table XI.M27-1 states, in part, A reference to a section includes all sub bullets unless otherwise noted.

Section 5.3.1 of the 2011 Edition of NFPA 25 includes sub bullets related to standard sprinklers, fast response sprinklers, dry sprinklers, sprinklers that have been in service for 75 years, and sprinklers subject to harsh environments.

Footnote 7 for GALL-SLR Report Table XI.M27-1 includes three options for wet pipe sprinkler systems (i.e., SLRA either provides evaluation demonstrating water not corrosive, one-time test of sprinklers exposed to water, or test in accordance with Section 5.3.1.1.2 of the 2011 Edition of NFPA 25).

Given that the SLRA only refers to the standard sprinkler replacement or testing frequency (Section 5.3.1.1.1 of the 2011 Edition of NFPA 25), its unclear whether the replacement and testing frequencies for fast response and dry sprinklers are applicable for Robinson, whether sprinklers that may reach 75 years in service during the SPEO are replaced or tested on a 5 year interval, and which option from Footnote 7 for GALL-SLR Report Table XI.M27-1 Robinson has selected.

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 48 3

Appendix A,

Appendix B

A-59, B-106 The corrective actions program element in GALL-SLR Report AMP XI.M27 states, If a flow test (i.e.,

NFPA 25 Section 6.3.1) or a main drain test (i.e.,

NFPA Section 13.2.5) does not meet acceptance criteria due to current or projected degradation (i.e.,

trending) additional tests are conducted. The number of increased tests is determined in accordance with the sites corrective action process; however, there are no fewer than two additional tests for each test that did not meet acceptance criteria. The additional inspections are completed within the interval (i.e., 5 years, annual) in which the original test was conducted.

Enhancements 5 and 7 in SLRA Table A6.0-1 and SLRA Section B2.1.16 state that at least two additional tests will be performed within five years and at least two additional tests will be performed within two years.

It is unclear what is meant by within 5 years and within 2 years.

The staff notes that similar language to The additional inspections are completed within the interval (i.e., 5 years, annual) in which the original test was conducted was added to other AMPs in GALL-SLR Report (e.g., XI.M18).

Table 2-29 of NUREG-2221 states that the additional flow tests and main drain tests are to provide sufficient data to determine whether flow blockage is localized or widespread. In addition, it states, It would not be acceptable to maintain the original inspection schedule when it is anticipated that Please provide additional details on when the additional tests for each flow test or main drain test that do not meet acceptance criteria will be performed, including the basis and whether changes to Enhancements 5 and 7 are need.

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 49 acceptance criteria would not be met.

Given that the intent is to promptly identify whether flow blockage is localized or widespread and to promptly identify if the timing of the next inspection is appropriate, clarification regarding within 5 years and within 2 years is needed.

4 Appendix B

B-104 The corrective actions program element in GALL-SLR Report AMP XI.M27 states, in part, Results that do not meet the acceptance criteria are addressed in the applicants corrective action program. In addition, the monitoring and trending program element in GALL-SLR Report AMP XI.M27 states that Visual inspection results are monitored and evaluated and Results of flow testing (e.g., buried and underground piping, fire mains, and sprinkler), flushes, and wall thickness measurements are monitored and trended.

SLRA Section B2.1.16 states, Abnormal results are entered into the corrective action program for review and resolution. Similar statements are made in SLR-RNP-AMPR-XI.M27 (Fire Water System program basis document).

However, Section 4.6 in the Fire Water System program basis document states, Abnormal conditions are documented and evaluated in completed work packages. Unacceptable conditions are documented in the corrective action program.

The staff notes that Section 4.1.3 of FP-013 defines abnormal degradation as A condition that is not expected or typical and renders the item non-functional.

Please clarify the following:

12. The meaning of abnormal and unacceptable conditions/results in this instance.
13. Are both abnormal and unacceptable conditions/results trended?

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 50 Given the difference in how abnormal is used in the SLRA and the Fire Water System program basis document (and how used in FB-013, Revision 21), it is unclear how the terms abnormal and unacceptable are used in these instances and how these conditions/results are monitored and trended.

5 Appendix A,

Appendix B

A-60, B-106 Section 4.4 of the Fire Water System program basis document states, The Robinson Fire Water System aging management program will be enhanced to require the sprinkler head removed for inspection in pre-action systems to be from the most remote branch line from the source of water that is not equipped with an inspectors test valve. The staff notes that this is consistent with Section 14.2.1.5 of the 2011 Edition of NFPA 25.

SLRA Table A6.0-1 and SLRA Section B2.1.16 includes enhancements related to Sections 14.2 and 14.2.2 of the 2011 Edition of NFPA 25. The enhancement related to Section 14.2 is specific to internal visual inspections of piping and branch lines by opening a flushing connection at the end of one main and by removing a sprinkler head toward the end of one branch line.

It is unclear whether it was the intent to include an enhancement related to Section 14.2.1.5 in the SLRA.

Please discuss whether it was the intent to include an enhancement related to Section 14.2.1.5 in the SLRA.

6 2.1.5.1 2-24, 2-131, 3-653 SLRA Tables 2.3.3-37 and 3.3.2-37 do not appear to include components associated with the diesel-driven fire pump engine (i.e., heat exchanger channel, shell, tube, and jacket water).

Please address the following:

14. Provide a technical basis for why the SLRA does not appear to address components associated with the diesel-driven fire pump

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 51 SRP-SLR Table 2.3-2, "Examples of Mechanical Components Screening and Basis for Disposition,"

states the following:

Diesel engine jacket water heat exchanger and portions of the diesel fuel oil system and starting air system supplied by a vendor on a diesel generator skid These are passive, long-lived components having intended functions. They are subject to an AMR for SLR even though the diesel generator is considered active.

In addition, SRP-SLR Table 2.1-6 reflects that heat exchangers are considered passive, long-lived components that are subject to AMR.

The staff is aware that the SLRA identifies diesel generators as an example of a complex assembly.

SRP-SLR Table 2.1-2 identifies diesel generator starting air skids as an example of a complex assembly and states, An applicant should establish the boundaries for such assemblies by identifying each structure and component that make up the complex assembly and determining whether or not each structures and component is subject to an AMR.

Note: There is a related question under Scoping and Screening.

engine (i.e., heat exchanger channel, shell, tube, and jacket water).

15. Discuss whether there has been any OE associated with any components associated with the diesel-driven fire pump engine (e.g., coolant leaks, tube bundle replacement, fouling, etc.), including what caused the degradation.
16. Identify the periodic maintenance procedures related to the diesel-driven fire pump engine.

7 N/A N/A Section 4.4 of the Fire Water System program basis document states that hose stations in the Reactor Containment Building, Reactor Auxiliary Building, Please provide additional information regarding why these hose stations are not flow tested.

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 52 Turbine Building, Intake Structure, Switchgear Building, and Fuel Handling Building are subject to flushing but are not flow tested.

8 N/A N/A Section 4.4 of the Fire Water System program basis document indicates that flow blockage is monitored for the traveling screens by monitoring differential pressure and that the traveling screens are automatically cleaned to remove accumulated debris.

It is unclear whether there is an alarm in the control room on low and/or high differential pressure and whether the traveling screens are also monitored through routine operator rounds.

SLRA Section B2.1.11 states that preventive maintenance IDs were created to replace traveling screens every 8 years based on a series of minor issues with the traveling screens.

The staff noted that there does not appear to be AMR items for the traveling screens in the SLRA which appears to be based on the fact that they are periodically replaced every 8 years.

Section 4.4 of the Fire Water System program basis document states the inlet basket strainer for the diesel-driven and motor-driven fire pumps are inspected for fouling and degradation every 6 years and 10 years, respectively, as part of pump overhaul.

The staff notes that SLRA Table 3.3.2-37 includes AMR items for strainers where flow blockage and loss of material are managed by the Fire Water System program.

Please discuss the following:

17. Is there an alarm in the control room on low and/or high differential pressure?
18. Are the traveling screens also monitored through routine operator rounds?
19. Is the staffs assumption correct that the traveling screens are not subject to AMR because they are periodically replaced?
20. Discuss whether there has been any OE associated with the traveling screens due to age related degradation (i.e., flow blockage and/or loss of material).
21. Discuss whether there has been any OE associated with the inlet basket strainers due to age related degradation (i.e., flow blockage and/or loss of material).

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 53 Water Chemistry Question Number SLRA Section SLRA Page Background / Issue Discussion Question / Request 1

N/A N/A On page 23 of the Root Cause Evaluation Report for Cycle 33 Coolant Pump Seal Performance it mentions that Robinson has had an increase in Primary Water Storage Tank Dissolved Oxygen over the past 22 years and that the dissolved oxygen levels were higher than the original equipment manufacturer (OEM) recommended value. It was also mentioned that Robinson was an outlier in terms of these dissolved oxygen levels. It is unclear to the staff what caused these excessive levels and if the issue has been resolved.

Please address the following:

g. Is Robinson still experiencing these high levels of Dissolved Oxygen?
h. Has the cause of these elevated dissolved oxygen levels been determined?
i.

Have there been any negative impacts on the primary system due to these elevated dissolved oxygen levels?

2 N/A N/A In the Root Cause Evaluation Report there was discussion regarding the buildup of excessive iron oxide deposits on the reactor coolant pump (RCP) seals. It is unclear to the staff what the cause of this buildup was and if the issue has been resolved.

Please address the following:

j. What was the cause of the iron oxide deposits and was it due to a failure to maintain proper primary system water chemistry?
k. Have these buildups been seen since changing out the RCP seals?
l.

Were there any negative impacts on the primary system due to these buildups of iron oxide?

3 Table 3.3.1 3-372 In SLRA Table 3.3.1 it states that the Table 1 item 3.3.1-169 is not applicable because the items are aligned to items in the steam and power conversion system exposed to a treated water environment. Based on that Please address the following:

m. Which alternative items in the steam and power conversion system items that would

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 54 description, it appears that this item is applicable but uses alternative AMR items. It is unclear to the staff which alternative items components that would be aligned to 3.3.1-169 are aligned to in the steam and power conversion system and the basis for choosing to align these items to a treated water environment when the environment listed for item 3.3.1-169 is steam.

be aligned to item 3.3.1-169 are aligned to.

n. The basis for aligning these items to items that have a treated water environment when the environment for 3.3.1-169 is steam.

4 Table 3.3.1 3-373 In SLRA Table 3.3.1 it states that the Table 1 item 3.3.1-170 is not applicable because the items are aligned to items in the steam and power conversion system exposed to a treated water environment. Based on that description, it appears that this item is applicable but uses alternative AMR items. It is unclear to the staff which alternative items components that would be aligned to 3.3.1-170 are aligned to in the steam and power conversion system and the basis for choosing to align these items to a treated water environment when the environment listed for item 3.3.1-170 is steam.

Please address the following:

o. Which alternative items in the steam and power conversion system items that would be aligned to item 3.3.1-170 are aligned to.
p. The basis for aligning these items to items that have a treated water environment when the environment for 3.3.1-170 is steam.

5 Table 3.5.1 and Table 3.5.2-13 3-947 and 3-1012 SLRA Table 3.5.2-13 states that the Water Chemistry and SMPs will be used to manage cracking and loss of material for the stainless steel spent fuel pool liner exposed to a treated borated water (external) environment. It appears that the SMP is being used to address the part of the aging management for GALL-SLR item 3.5.1-078 that recommends monitoring of the spent fuel pool water level and leakage from the leak chase channels. However, the discussion for this item in SLRA Table 3.5.1 does not mention the SMP. Similarly, the SMP is not mentioned in the plant-specific note 4 in Table 3.5.2-13. Therefore, how fuel pool water level and leak chase monitoring are related to the SMP is unclear Please address the following:

q. How the SMP is being used to manage cracking and loss of material for the stainless steel spent fuel pool liner exposed to a treated borated water (external) environment in relation to monitoring the spent fuel pool water level and leakage from the leak chase channels.
r. How the use of the Structures Monitoring Program is consistent with GALL-SLR.

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 55 to the staff.

Selective Leaching Question Number SLRA Section SLRA Page Background / Issue Discussion Question / Request 1

N/A N/A SLR-RNP-AMPR-XI.M33, Selective Leaching AMP Evaluation Report, states [s]usceptible buried components within the scope of this program include ductile iron and gray cast iron piping coated per L2-C-007, Field Coatings.

L2-C-007 has a product data sheet for a coal tar epoxy meant for burial exposure, to be applied at 16-20 mils (page 133/172). Is this the coating that is being referred to?

2 N/A N/A GALL-SLR Report AMP XI.M33, Selective Leaching, states

[s]usceptible materials exposed to high operating temperatures, stagnant-flow conditions [emphasis added by staff], and a corrosive environment (e.g., acidic solutions for brasses with high zinc content and dissolved oxygen) are conducive to selective leaching.

SLR-RNP-AMPR-XI.M33, Selective Leaching AMP Evaluation Report, Revision 0 states the following:

  • [f]or populations of the same material, raw water and waste water environments will be combined.
  • [i]n the Auxiliary Boiler/Steam system, the waste evaporators and the boric acid recycler subsystem are retired in place and isolated. The once chemically controlled treated water within is now isolated and stagnant. Per engineering discretion this water is now deemed to be waste water. There are gray cast iron and ductile iron components in this environment.

The staff requests a discussion on the subject components, specifically whether targeted inspections are appropriate given the stagnant-flow conditions. It is unclear to the staff if these components will be inspected since raw and waste water populations will be combined.

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 56 3

B2.1.21 B-133 SLRA Section B2.1.21, Selective Leaching, states

[s]usceptible components exposed to soil will be excluded from inspection due to all in scope external surfaces being coated and review of OE reveals no indication of coating damage.

SLR-RNP-AMPR-XI.M33, Selective Leaching AMP Evaluation Report, indicates that there were two instances of coating damage to buried carbon steel piping, but the damage was not due to age-related degradation.

AR 85018, License Renewal Commitment #35 - Selective Leaching - Site Fire Protection System, include discussions of buried piping with thin, breached, and missing coatings.

The OE discussion in SLRA Section B2.1.27, Buried and Underground Piping and Tanks, includes several references to buried piping with damaged external coatings, for example: [i]n 2013, two fuel oil pipeswere inspected

[i]nspection of the coal tar epoxy coated carbon steel pipes identified areas of pitting on both pipes...[t]he suspected cause of the corrosion was due to age-related localized coating failure that allowed moisture in the soil to contact the outside of the pipe.

Based on its review of plant-specific OE, the staff requests a discussion on the exclusion of buried components from inspection based on the condition of external coatings.

ASME Code Class 1 Small-Bore Piping Question Number SLRA Section SLRA Page Background / Issue Discussion Question /

Request 1

B2.1.22 B-138 Robinson SLRA Section B2.1.22, "ASME Code Class 1 Small-Bore Piping," (Page B-138) states that there are 136 butt welds in the small-bore piping population at Robinson.

1) Are the 50 BMI full penetration butt welds included in the "136 butt welds" for

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 57 Duke Energy document on the e-Portal NDE-NE-ALL-7203, Rev 3, "

"Visual Examination of PWR Reactor Pressure Vessel Bottom Mounted Instrument [BMI] Penetrations," Figures 5 and 6, seem to indicate the presence of 50 full penetration butt welds for the Robinson BMI penetrations.

Questions:

1) Are the 50 BMI full penetration butt welds included in the "136 butts welds" for Robinson SLRA AMP B2.1.22?
2) What is the ASME Code,Section XI, Examination Category for the 50 BMI full penetration butt welds?

Robinson's SLRA AMP B2.1.22?

2) What is the ASME Code,Section XI, Examination Category for the 50 BMI butt welds?

Flux Thimble Tube Inspection Question Number SLRA Section SLRA Page Background / Issue Discussion Question / Request 1

B2.1.24 SRLA Section B2.1.24 contains an enhancement, which states:

Prior to the subsequent period of extended operation, the following enhancement(s) will be implemented in the following program elements: Acceptance Criteria (Element 6)

22. The program will be enhanced to allow only the acceptance criteria that was previously submitted in the original response letter to NRC Bulletin 88-09.

(Element 6)

In its letter dated February 8, 1991 (MLXXXX), the applicant provided its response to NRC Bulletin 88-09 that states, in part, that "the results of this analysis show that the calibration The applicant's enhancement in SLRA Section B2.1.24 seems to intentionally restrict the acceptance criteria for the Flux Thimble Tube Inspection Program to that of the applicant's response to NRC Bulletin 88-09, which is already part of the existing program/procedure.

  1. 1 - Clarify the intent/purpose of the enhancement in SLRA Section B2.1.24 given that the existing procedure/program already incorporates the criterion established in the

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 58 tube at HBR2 can lose 65 percent of its wall thickness without exceeding ASME Code material allowables under design condition."

The plant procedure for the Flux Thimble Tube Inspection Program (EST-108, Rev 14) indicates that the acceptance criterion for the calibration (inner) tube is consistent with the results of the analysis conducted to support the applicant's response to NRC Bulletin 88-09 (i.e., the calibration tube at HBR2 can lose 65 percent of its wall thickness without exceeding ASME Code material allowables under design condition).

applicant's response to NRC Bulletin 88-09, which seems to be consistent with the "acceptance criteria" program element of GALL-SLR AMP XI.M37.

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 59 2

B2.1.24 SLRA Section B2.1.24 provides OE information related to the Flux Thimble Tube Inspection Program and referenced letter dated April 13, 2009 (ML091100397), which provided the basis for extending the inspection interval of the flux thimble tubes to ever sixth refueling outage.

At the time of this letter, Robinson, Unit 2, had been performing inspections every other refueling outage, which was approximately every 3 years, and the last inspection of the flux thimble tubes was performed during RO-23 (September 2005).

The PM work order 10059310 indicates that flux thimble tube inspections are performed approximately every 8 years. The staff understands that Robinson Unit 2 has transitioned to 24-month refueling cycles since the time of the letter referenced above.

Based on the discussion of OE in SLRA Section B2.1.24 and the documents initially available during the audit, the staff noted that it does not provides objective evidence/information regarding the performance of the program as it relates to the to the inspection the flux thimble tubes during the period that Robinson Unit 2 entered their "first" period of extended operation. Based on the information from the 2009 letter and the PM work order - it appears to the staff that at least one inspection of the flux thimble tubes would have been performed since 2005.

  1. 1 - Clarify whether additional inspections of the flux thimble tubes have been performed since RO-23 (Sept 2005) - If yes, please identify the refueling outage(s) and associated month/year. If no, please explain.
  1. 2a - Confirm whether these results were consistent with those identified during the previous inspections, with the latest results from RO-23 indicating that no wall loss or damage was detected in any of the 47 tubes.

If not - discuss these results that were not consistent, including the cause for any degradation, damage, wall loss, etc.

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 60 Buried and Underground Piping and Tanks Question Number SLRA Section SLRA Page Background / Issue Discussion Question / Request 1

B2.1.27 B-161 Enhancement No. 1 states [c]omplete a modification to replace the buried steel Dedicated Shutdown Diesel Generator piping within the scope of this program with aboveground piping.

The staff requests a discussion on this enhancement, specifically related to the following:

23. It is the staffs understanding that this enhancement was added since the station did not want to retrofit the cathodic protection system to protect this piping (as opposed to a degradation issue associated with this piping that required moving the piping aboveground). Is this correct?
24. It is unclear to the staff why the enhancement does not specify a completion time (e.g., prior to entering the SPEO). In addition, it is unclear to the staff why the enhancement does not specify actions to be completed if the piping replacement does not take place prior to the completion time. For example, Enhancement No. 2 outlines specific inspections if the service water piping modification is not completed prior to entering the SPEO.

2 B2.1.27 B-161 Enhancement No. 2 states [c]omplete a modification to remediate the existing buried concrete lined steel service water intake piping within the scope of this program[i]f the service water modification is not completed prior to entering the SPEO, inspection of the buried service water piping will be performed in the 10-year period prior to entering the SPEO. Inspections will be performed The staff requests a discussion on this enhancement, specifically related to the following:

25. What methods of remediation are being considered (e.g., CFRP)?
26. It is unclear why a 1% external visual sample size was selected, considering that this sample size aligns with Preventive Action Category D in

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 61 on either the external or internal surfaces of the buried piping. If external piping or coating surfaces are inspected [t]he extent of the visual inspections will be either 1% of the piping length (16 feet) or two inspections of 10 feet each. If internal piping surfaces are inspected, the internal inspection method will utilize a volumetric nondestructive examination technique capable of measuring wall thickness and detecting depth of pits.

GALL-SLR Report AMP XI.M41, Buried and Underground Piping and Tanks. This Preventive Action Category is for instances where it has been demonstrated that external corrosion control is not required.

27. Results of any inspections (or other rationale) which demonstrate that internal volumetric examinations produce accurate results on a rough/degraded concrete surface.
28. Will the inspections described in the enhancement be in addition to the required XI.M42 visual inspections for loss of material and loss of coating integrity?

3 B2.1.27 B-161 Enhancement No. 3 states [m]aintain a structure to soil potential less negative than -1,200 mV.

It is unclear to the staff why the enhancement does not specify: (a) instant-on or instant-off; or (b) the type of reference electrode (e.g., copper/copper sulfate) the potential is measured against.

4 B2.1.27 B-162 Enhancement No. 5 states [s]pecify that backfill placed within 6 inches of buried non-Seismic Class I piping within the scope of the program will meet or exceed the objectives of ASTM D448-08 size 67.

The staff requests a discussion on this enhancement, specifically related to (a) why the enhancement is limited to non-Seismic Class I piping; and (b) why size 10 is not specified for buried polymeric materials (e.g.,

PVC).

5 B2.1.27 B-162 Enhancement No. 6 states [u]tilize an inspection method that has been demonstrated to be capable of detecting cracking when inspections of uncoated stainless steel piping are performed.

The staff requests a discussion on the following to establish a basis for why external coatings are not necessary for in-scope uncoated buried stainless steel piping: (a) any historical inspection results of uncoated buried stainless steel piping; and (b) results of soil corrosivity testing (e.g., chlorides) conducted in the vicinity of in-scope uncoated buried stainless steel

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 62 piping.

6 B2.1.27 B-163 Enhancement No. 13 states [p]erform visual inspections of the concrete encapsulated components in the North service water header (30-CW-11) at pit #3 at least once in the 10-year period prior to entering the subsequent period of extended operation.

The staff requests a discussion on this enhancement, specifically related to the following:

29. What is the sample size for this inspection?
30. Will periodic inspections of this piping continue into the SPEO if the service water modification is not completed prior to entering the SPEO?

7 B2.1.27 B-163 Enhancement No. 16 states [i]nspect polyvinyl chloride components in the scope of the program for absence of cracking and perform an evaluation when blisters, gouges, or wear is detected.

It is unclear to the staff why the enhancement does not specify the sample size and inspection frequency.

8 B2.1.27 B-160 SLRA Section B2.1.27, Buried and Underground Piping and Tanks, states [i]n addition, opportunistic visual inspections of the external surface of buried Site Fire Protection System piping are performed when the piping is excavated for any reason.

Since this includes ductile iron and gray cast iron piping, it is unclear to the staff why mechanical examination techniques (e.g., chipping, scraping) will not augment visual inspections to detect loss of material due to selective leaching.

9 B2.1.27 B-160 SLRA Section B2.1.27 states [t]he program relies on monitoring of system header pressure and triennial flow testing for aging management of the buried piping in the Site Fire Protection System.

The staff requests a discussion on why the program will not be enhanced to align with the annual flow testing frequency prescribed in GALL-SLR Report AMP XI.M41, Buried and Underground Piping and Tanks.

10 N/A N/A SLR-RNP-AMPR-XI.M33, Selective Leaching AMP Evaluation Report, Revision 0 states [c]athodic protection has not been installed on buried piping at Robinson other than Fuel Oil system piping.

It is the staffs understanding that in-scope buried steel piping (other than fuel oil system piping) will be replaced with a different material that doesnt require cathodic protection or will be replaced with aboveground piping. The staff requests on discussion on this topic to ensure that this is an accurate

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 63 assessment.

11 B2.1.27 B-165 and B-166 The staff noted the following based on its review of OE in SLRA Section B2.1.27, Buried and Underground Piping and Tanks:

  • OE example 2(a) states [i]n 2008, a Unit 1 Site Fire Protection System pipe feeding fire hydrant was visually inspected. The cast iron pipe was uncoated and buried in moist/damp sand clay soil at a depth of three feet below grade.
  • OE example 2(d) states [t]he suspected cause of the leak was due to damage from a rock located adjacent to the pipe.
  • OE example 2(h) states [a] 5/8-inch hole was found at the damage location which was caused by a rock or other hard material next to the pipe (likely due to demolition of a nearby building).

The staff request a discussion with respect to the extent of (a) uncoated in-scope buried piping; and (b) non-conforming backfill in the vicinity of in-scope piping.

12 A2.1.27 A-22 and A-23 GALL-SLR Report Table XI-01, FSAR Supplement Summaries for GALL-SLR Report Chapter XI Aging Management Programs, includes the following statement for AMP XI.M41: [w]here the coatings, backfill or the condition of exposed piping does not meet acceptance criteria such that the depth or extent of degradation of the base metal could have resulted in a loss of pressure boundary function when the loss of material rate is extrapolated to the end of the subsequent period of extended operation, an increase in the sample size is conducted.

The staff requests a discussion with respect to why this statement is not included in SLRA Section A2.1.27.

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 64 13 N/A N/A SLR-RNP-AMPR-XI.M41, Buried and Underground Piping and Tanks AMP Evaluation Report, Appendix C, Buried Piping Inspection Summaries, includes references to buried cementitious fire protection piping (OE examples #67 and #86).

It is the staffs understanding that this piping is out-of-scope and there is no in-scope buried cementitious piping. The staff requests discussion on this topic to ensure that this is an accurate assessment.

Internal Coatings / Lining Question Number SLRA Section SLRA Page Background / Issue Discussion Question / Request 1

B2.1.28 B-173 to B-179 The Program Basis Document SLR-RNP-AMPR-XI.M42, Rev. 1 on the applicant Portal states that components in the scope of the AMP come from the following systems:

  • Closed Cycle Cooling Water System heat exchanger heads, tubesheets, and valve bodies
  • Fire Protection System fire hydrants, piping, and valve bodies
  • Fuel Oil System diesel fuel oil storage and vertical fuel oil storage tanks
  • Containment Pressure Relief System valve bodies
  • Containment Vacuum Breaker System Be prepared to discuss additional known OE (if applicable) from the following in-scope systems that provides objective evidence that SLRA Section B2.1.28 AMP inspections will be effective in identifying and managing aging effects and loss of coating integrity for these systems:
  • Fuel Oil System diesel fuel oil storage and vertical fuel oil storage tanks
  • Containment Pressure Relief System valve bodies
  • Containment Vacuum Breaker System valve bodies
  • Safety Injection System valve bodies
  • Spent Fuel Pool Cooling System valve bodies Note: Staff intends for this discussion to be limited to the OE Audit and associated breakouts only. The

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 65 valve bodies

  • Safety Injection System valve bodies
  • Spent Fuel Pool Cooling System valve bodies SLRA Section B2.1.28, Operating Experience, describes OE examples from four of the above systems (the Closed Cycle Cooling Water, service water, Fire Protection and Reactor Coolant Systems) and states that the aging management activities and methods to be implemented by the applicants AMP will be effective to manage aging effects prior to loss of intended function for the subsequent period of extended operation (SPEO).

staff does not require that additional OE examples should be added to the SLRA.

2 Tables 3.3.2-1 through 3.3.2-40 3-450, -

601, -602, -

611, -612, -

619, -621, -

622, -689 The Industry Standard Notes for SLRA Tables 3.3.2-1 through 3.3.2-40 define note A, in part, as AMP is consistent with NUREG-2191 AMP while note E is defined, in part, as a different AMP is credited or NUREG-2191 identifies a plant-specific AMP. However, for the components listed below and for which Industry Standard Note A is specified, the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program is substituted for the Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks program.

  • Table 3.3.2-4: AMR IDs 6673, 6671
  • Table 3.3.2-27: AMR IDs 676, 667
  • Table 3.3.2-30: AMR IDs 894, 7308
  • Table 3.3.2-31: AMR IDs 4226, 4043, Explain why Industry Standard Note A should be specified for the SLRA Tables 3.3.2-4, 3.3.2-27, 3.3.2-30, and 3.3.2-31 AMR Items where the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program is substituted for the Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks program.

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 66 4224, 4047, 4225, 4045, 4130, 4131, 4095, 4180, 4181, 4099 3

Table 3.3.2-4 3-450 SLRA Table 3.3.2-4 lists component cooling water system valve body(s) which are internally coated carbon steel and for which the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program is proposed to manage for the aging effects of loss of material and loss of coating or lining integrity. Plant-Specific Note 7 justifies this by claiming that the component(s) meets the six criteria in GALL-SLR AMP XI.M42, Element 4, to manage loss of coating or lining integrity under an alternate AMP.

Of the six GALL-SLR criteria referenced in plant-specific note 7, NRC staff were only able to verify from the docketed application that the component(s) only current licensing basis intended function is structural integrity. NRC staff notes that the basis for utilizing an alternative AMP should be docketed so that the staff can evaluate these AMR items and properly document this evaluation in its safety evaluation report (SER).

SLR-RNP-AMPR-XI.M42, Rev. 1 on the Portal provides additional information for the component(s) on downstream effects, internal environment, galvanic coupling, and corrosion allowance. Be prepared to discuss the following:

  • Show from the drawings posted on the Portal (or alternate drawings if necessary) which valves are represented in SLRA Table 3.3.2-4, AMR IDs 6673 and 6671.
  • Elaborate on the statement in SLR-RNP-AMPR-XI.M42 that the abandoned equipment is isolated from the in service portion by normally closed valves (i.e. are these valves always closed when operating?

are they frequently opened during shutdown? are they sometimes but rarely opened during shutdown?)

  • Is the water inside the abandoned equipment ever flushed out, and if so how are downstream effects from potentially detached coatings/linings managed during these operations?
  • How is the level of chromate managed inside the abandoned equipment?

4 Table 3.3.2-27 3-601 through -

603 SLRA Table 3.3.2-27 lists Penetration Pressurization Local Leak Rate Test air receiver tanks which are internally coated carbon steel and for which the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting SLR-RNP-AMPR-XI.M42, Rev. 1 on the Portal provides additional information for these components on downstream effects, internal environment, galvanic coupling, and corrosion

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 67 Components program is proposed to manage for the aging effects of loss of material and loss of coating or lining integrity. Plant-Specific Note 1 justifies this by claiming that the component(s) meets the six criteria in GALL-SLR AMP XI.M42, Element 4, to manage loss of coating or lining integrity under an alternate AMP.

Of the six GALL-SLR criteria referenced in plant-specific note 1, NRC staff were only able to verify from the docketed application that the component(s) only current licensing basis intended function is structural integrity. NRC staff notes that the basis for utilizing an alternative AMP should be docketed so that the staff can evaluate these AMR items and properly document this evaluation in its SER.

allowance. Be prepared to discuss the following:

  • Describe if these tanks have any threaded connections.
  • Describe any known OE (if applicable) indicating a history of internal corrosion with these tanks.
  • Is there any potential for detached coatings/linings to cause failure of components downstream of the tanks, and would this component failure prevent the satisfactory accomplishment of any of the functions identified in 10 CFR 54.4(a)(1), (2),

or (3)?

5 Table 3.3.2-30 3-611 to -

612 SLRA Table 3.3.2-30 lists a Potable Water System water heater which is internally coated carbon steel and for which the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program is proposed to manage for the aging effects of loss of material and loss of coating or lining integrity. Plant-Specific Note 3 justifies this by claiming that the component(s) meets the six criteria in GALL-SLR AMP XI.M42, Element 4, to manage loss of coating or lining integrity under an alternate AMP.

Of the six GALL-SLR criteria referenced in plant-specific note 3, NRC staff were only able to verify from the docketed application that the component(s) only current licensing basis intended function is structural integrity. NRC staff SLR-RNP-AMPR-XI.M42, Rev. 1 on the Portal provides additional information for this component on downstream effects, internal environment, galvanic coupling, and corrosion allowance. Be prepared to discuss the following:

  • Describe if the hot water heater is intended to be repaired or replaced at a defined interval or date during the period of extended operation.
  • Is the hot water heater drained, flushed, or maintained at regular intervals during the licensing period? If so, discuss the maintenance procedure controlling these operations.
  • Confirm that the water flowing into the water

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 68 notes that the basis for utilizing an alternative AMP should be docketed so that the staff can evaluate these AMR items and properly document this evaluation in its SER.

heater is demineralized and chemically treated.

  • Describe the components in the hot water line downstream of the hot water heater.
  • Would detached coatings/linings from the water heater simply exit the system, or could they remain trapped in the system? If the potential for trapping detached coatings/linings exists, would this lead to component failure preventing the satisfactory accomplishment of any of the functions identified in 10 CFR 54.4(a)(1), (2), or (3)?
  • SLR-RNP-AMPR-XI.M42 states that "the hot water heater presents a larger anode relative to connected copper piping." Elaborate on the relative size differences of the system anode (steel tank) and cathode (copper piping). If the water heater tank is well coated except for a small defect or holiday, does this make an undesirable galvanic couple?

6 Table 3.3.2-31 3-619, -

621, -622, -

624 SLRA Table 3.3.2-31 lists several Primary and Demineralized Water Makeup System tanks and valves which are internally coated carbon steel, ductile iron, or gray cast iron and for which the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program is proposed to manage for the aging effects of loss of material and loss of coating or lining integrity.

Plant-Specific Note 7 justifies this by claiming that the component(s) meets the six criteria in GALL-SLR AMP XI.M42, Element 4, to manage loss of coating or lining integrity under an SLR-RNP-AMPR-XI.M42, Rev. 1 on the Portal provides additional information for these components (Primary and Demineralized Water Makeup System tanks and valves) on downstream effects, internal environment, galvanic coupling, and corrosion allowance. Be prepared to discuss the following:

  • Describe the most corrosive water chemistry anticipated for these components. Which component(s) is(are) likely to see the most corrosive water chemistry conditions?

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 69 alternate AMP.

Of the six GALL-SLR criteria referenced in plant-specific note 7, NRC staff were only able to verify from the docketed application that the component(s) only current licensing basis intended function is structural integrity. NRC staff notes that the basis for utilizing an alternative AMP should be docketed so that the staff can evaluate these AMR items and properly document this evaluation in its SER.

  • Discuss the impact to the operations of the Primary and Demineralized Water Makeup System if coatings/linings became detached.

Could detached coatings/linings lead to component failure preventing the satisfactory accomplishment of any of the functions identified in 10 CFR 54.4(a)(1), (2), or (3)?

7 Table 3.4.2-1 through 3.4.2-14 3-866, -869 The Industry Standard Notes for SLRA Tables 3.4.2-1 through 3.4.2-14 define note A, in part, as AMP is consistent with NUREG-2191 AMP while note E is defined, in part, as a different AMP is credited or NUREG-2191 identifies a plant-specific AMP. However, Table 3.4.2-14, AMR IDs 3254 and 3257 specify Industry Standard Note A, although the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program is substituted for the Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks program.

Explain why Industry Standard Note A should be specified for the SLRA Table 3.4.2-14 AMR Items where the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program is substituted for the Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks program.

8 Table 3.4.2-14 3-866, -868 SLRA Table 3.4.2-14 lists a Turbine-Generator Lube Oil System tank which is internally coated carbon steel and for which the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program is proposed to manage for the aging effects of loss of material and loss of coating or lining integrity. Plant-Specific Note 3 justifies this by claiming that the SLR-RNP-AMPR-XI.M42, Rev. 1 on the Portal provides additional information for this component on downstream effects, internal environment, galvanic coupling, and corrosion allowance. Be prepared to discuss the following:

  • Elaborate on the statement on page 27 of SLR-RNP-AMPR-XI.M42 that lubricating oil

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 70 component(s) meets the six criteria in GALL-SLR AMP XI.M42, Element 4, to manage loss of coating or lining integrity under an alternate AMP.

Of the six GALL-SLR criteria referenced in plant-specific note 3, NRC staff were only able to verify from the docketed application that the component(s) only current licensing basis intended function is structural integrity. NRC staff notes that the basis for utilizing an alternative AMP should be docketed so that the staff can evaluate these AMR items and properly document this evaluation in its SER.

is regularly monitored and normally does not contain a gross amount of water.

  • Will the lubricating oil in this tank be monitored by the SLRA Lubricating Oil Analysis AMP?
  • Is there any potential for detached coatings/linings to cause failure of components downstream of the tanks, and would this component failure prevent the satisfactory accomplishment of any of the functions identified in 10 CFR 54.4(a)(1), (2),

or (3)?

9 B2.1.28 B-173 to B-179 Action Request (A/R) 00630381 on the applicant Portal provides OE on minor coating degradation identified during the cleaning and inspection of the hydrogen side seal oil cooler. According to A/R 00630381, repairs were to be made per "PM WO 02065465-08." Applicant Work Order (WO)

Information Report ST2900, also on the Portal, provides information on WO 12065465-08 (see pages 17 to 19) to "PREP AND PAINT/TOUCH UP H2 SIDE SEAL OIL COOL COVERS." But the timeline and status of the actions taken in WO 12065465-08 are unclear to the staff.

Please clarify the timeline and the actions taken that are documented in ST2900 WO 12065465-08 on the applicant Portal. Verify that the repairs to the minor coating degradation specified in A/R 00630381 have been completed.

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 71 Reactor Head Closure Studs Bolting Question Number SLRA Section SLRA Page Background / Issue Discussion Question / Request 1

B2.1.3 SLRA Section B2.1.3 contains an enhancement, which states:

Prior to the subsequent period of extended operation, the following enhancements will be implemented in the following program elements:

Preventive Actions (Element 2) and Corrective Actions (Element 7).

1. Procurement requirements for reactor head closure stud bolting will be revised to incorporate guidance from RG 1.65, Revision 1 and NUREG-2191, Chapter XI.M3, to ensure newly procured bolting material for closure studs does not exceed a maximum actual yield strength of 150 ksi The applicants enhancement in SLRA Section B2.1.3 seems to already exist in the applicants procedures and specifications.
31. Clarify the intent/purpose of the enhancement in SLRA Section B2.1.3 given that the existing procedure/program seems to already incorporate the procurement requirements for reactor head closure stud bolting material to not exceed a maximum actual yield strength of 150 ksi.

Structures Monitoring Program Question Number SLRA Section SLRA Page Background / Issue Discussion Question / Request 1

B2.1.34 B-205 The SMP basis document (SLR-RNP-AMPR-XI.S6) states Examples of SCs and commodities in the scope of the program are concrete and steel structures, structural bolting, anchor bolts and embedments, component support members, supports and bracings associated with masonry Scope of Program:

32. Clarify whether the following components are within the scope of SLRA and, if so, include corresponding Table 2 AMR items in SLRA.
  • pipe whip restraints and jet impingement

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 72 walls, pipe whip restraints and jet impingement shields, transmission towers, panels and other enclosures, racks, sliding surfaces, spent fuel pool and reactor building cavity liners, electrical cable trays and conduits, electrical duct banks, manholes, doors, penetration seals, seismic joint filler, sump and pool liners, roofing, and other elastomeric materials, and tube tracks. However, no explicit table 2 items are presented in the SLRA for the following items:

  • pipe whip restraints and jet impingement shields
  • transmission towers
  • tube tracks SLR-RNP-AMPR-XI.S6 states Trash racks associated with water-control structures are within the scope of Water-Control Structures (XI.S7). However, no table 2 items for trash racks are presented in the SLRA.

SLRA Section 2.4.1 states Conduit, cable trays, cabinets, enclosures, racks, frames and panels for electrical equipment and instrumentation are evaluated in the Miscellaneous Structural Commodities group. These components are different from the components described in SLRA Section 2.4.18 and Table 3.5.2-18.

SLR-RNP-AMPR-XI.S6 states The Robinson Structures Monitoring aging management program describes the monitoring of sliding surfaces under the parameters monitored for structural and miscellaneous building steel as fluorogold friction plates. SLRA Table 3.5.1 claims that AMR Item 3.5.1-074 is consistent with NUREG-2191, however, shields

  • transmission towers
  • tube tracks
  • trash racks
2. Address the discrepancies between the components in the Miscellaneous Structural Commodities group described in SLRA Section 2.4.1 and those presented in SLRA Section 2.4.18 and Table 3.5.2-18.
3. Provide table 2 AMR items associated with AMR Item 3.5.1-074. If such items are not applicable, provide justification.

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 73 no table 2 items associated with AMR Item 3.5.1-074 are provided in SLRA.

2 B2.1.34 B-205 SLRA Section B2.1.34 specifies in which program elements Enhancements 2, 5, 7, 10, and 12 will be implemented as follows:

  • Enhancement 2: Element 1
  • Enhancement 5: Element 3, 4, and 6
  • Enhancement 7: Element 3 and 4
  • Enhancement 10: Element 4
  • Enhancement 12: Element 4 and 5 However, it appears that the above enhancements are implemented in additional program elements described in GALL-SLR Report,Section XI.S6. For example, Enhancement 2 is concerned with monitoring and evaluation on a frequency not to exceed five years, which is described in the Detection of Aging Effects program element (Element 4) of GALL-SLR Report,Section XI.S6.

Enhancements:

4. Clarify if Enhancement 2 will also be implemented in Element 4.
5. Clarify if Enhancement 5 will also be implemented in Element 1.
6. Clarify if Enhancement 7 will also be implemented in Element 6.
7. Clarify if Enhancement 10 will also be implemented in elements 1, 3 and 6.
8. Clarify if Enhancement 12 will also be implemented in Element 7.

3 B2.1.34 B-205 Enhancement 6 to the SMP, in part, states The program will be enhanced to explicitly mention loss of material, the changes in material properties of increase in porosity and permeability, and loss of strength, which can be indicated by honeycombs, discoloration, water in-leakage and pattern cracking with darkened edges.

However, SLRA Sections 3.5.2.2.2.1 and 3.5.2.2.2.3 state Structures Monitoring (B2.1.34) program inspections include examination for pattern cracking with darkened crack edges, water ingress, and Enhancements:

Address the inconsistency in the descriptions of Alkali-Silica Reaction in Enhancement 6 to the SMP and SLRA Sections 3.5.2.2.2.1 and 3.5.2.2.2.3.

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 74 misalignment inspections. Alkali-Silica Reaction inspection results are evaluated by the responsible engineer to identify changes that could be indicative of Alkali-Silica Reaction development (pattern cracking with darkened edges).

Descriptions of Alkali-Silica Reaction in SLRA Sections 3.5.2.2.2.1 and 3.5.2.2.2.3 are aligned with those in SRP-SLR Sections 3.5.3.2.1.8, 3.5.3.2.2.1, and 3.5.3.2.2.3, which state that accessible concrete exhibits visual indications of aggregate reactions, such as map or patterned cracking, alkali-silica gel, exudations, surface staining, expansion causing structural deformation, relative movement or displacement, or misalignment/distortion of attached components.

There is a discrepancy between Enhancement 6 to the SMP and SLRA Sections 3.5.2.2.2.1 and 3.5.2.2.2.3.

4 B2.1.34 B-205 Enhancement 8 to the SMP, in part, states Monitor and trend through-wall groundwater leakage, infiltration volumes, and leakage water chemistry for signs of concrete or steel reinforcement degradation.

Parameters Monitored or Inspected program element of GALL-SLR Report,Section XI.S6 states, in part If through-wall leakage or groundwater infiltration is identified, leakage volumes and chemistry are monitored and trended for signs of concrete or steel reinforcement degradation.

Through-wall leakage and groundwater infiltration are distinct phenomena and through-wall groundwater Enhancements:

Address the inconsistency in the description of through-wall leakage and groundwater infiltration in Enhancement 8 to the SMP.

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 75 leakage alone does not cover both of them.

5 Table 3.3.1 3-355 GALL-SLR Item VII.A1.A-94, associated with AMR Item 3.3.1-111, addresses the aging effect of loss of material due to general, pitting, crevice corrosion for steel components of new fuel storage racks.

UFSAR Section 9.1.1, New Fuel Storage describes the new fuel storage racks but does not provide sufficient information regarding their structural components and the material of construction.

Discussion column for SLRA Table 3.3.1, AMR Item 3.3.1-111 states Not applicable. Steel structural steel are Civil / Structural components and addressed by SRP items in Section 3.5. The associated NUREG-2191 aging items are not used.

However, it is not clear what AMR items in Section 3.5 are used to address AMR Item 3.3.1-111. In addition, AMR Item 3.3.1-111 is not used because other AMR items are used instead.

9. Describe the primary structural components and the material of construction for the new fuel storage racks.
10. Describe the primary structural components and the material of construction for the new fuel storage racks.
11. Clarify how the aging effects associated with the new fuel storage racks will be managed during the SPEO.
12. Clarify whether wording Not applicable should be changed into wording Not used in the Discussion for SLRA Table 3.3.1, AMR Item 3.3.1-111 and clarify what table 1 AMR items in Section 3.5 are used to address AMR Item 3.3.1-111.

6 Table 3.5.2-16; Table 3.5.2-28 3-1020; 3-1055 AMR IDs 576 and 581 in SLRA Table 3.5.2-16 are associated with AMR Item 3.5.1-054, which addresses the aging effect of cracking due to expansion from reaction with aggregates for all accessible areas of concrete structures except Group 6 exposed to any environment.

SLRA Table 3.5.2-16 is for Intake Structure, which is a Group 6 structure. AMR Item 3.5.1-096 addresses the same aging effect, mechanism, and environment for Group 6 structures.

13. Clarify whether AMR Item 3.5.1-096 should be used for AMR IDs 576 and 581 in SLRA Table 3.5.2-16, Intake Structure.
14. For AMR IDs 576 and 581 in SLRA Table 3.5.2-16 and for the items in SLRA Table 3.5.2-28 associated with AMR Item 3.5.1-054, clarify whether other applicable environments such as air-indoor, uncontrolled, water-flowing, and groundwater/soil environments should be considered for the aging effect of cracking due to expansion from reaction with

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 76 AMR IDs 576 and 581 in SLRA Table 3.5.2-16 contain identical information, considering only the Air-Outdoor (External) environment. AMR Item 3.5.1-054 used for Turbine Building in SLRA Table 3.5.2-28 also considers only the Air-Outdoor (External) environment. However, the aging effect of cracking due to expansion from reaction with aggregates can be due to additional environments, such as air-indoor, uncontrolled, water-flowing, and groundwater/soil environments.

aggregates.

7 Table 3.5.2-18; Table 3.5.2-8 3-1026; 3-999 AMR Item 3.5.1-067 and GALL Item III.A3.TP-28 address the aging effects of increase in porosity and permeability; cracking; loss of material (spalling, scaling) due to aggressive chemical attack for interior and above-grade exterior concrete exposed to air-indoor, uncontrolled and air-outdoor environments.

However, only the air-indoor, uncontrolled environment is considered for Drains/Curbs in SLRA Table 3.5.2-18.

AMR Item 3.5.1-077 and GALL Item III.A3.TP-302 address the aging effect of loss of material due to corrosion for all structural steel components exposed to air-indoor, uncontrolled and air-outdoor environments. However, only the air-indoor, uncontrolled environment is considered for steel elements of Condensate Polishing Building in SLRA Table 3.5.2-8.

SLRA does not make clear whether Drains/Curbs (SLRA Table 3.5.2-18) and steel elements of Condensate Polishing Building (SLRA Table 3.5.2-8) are exposed to air-outdoor environment.

15. For AMR IDs 576 and 581 in SLRA Table 3.5.2-18, clarify if Drains/Curbs are exposed to air-outdoor environment. If yes, provide table 2 AMR items associated with AMR Item 3.5.1-067 in the air-outdoor environment.
2. In SLRA Table 3.5.2-8, clarify if steel elements of the Condensate Polishing Building are exposed to air-outdoor environment. If yes, provide table 2 AMR items associated with AMR Item 3.5.1-077 in the air-outdoor environment.

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 77 8

Table 3.5.2-26 3-1052 AMR Item 3.5.1-079 addresses the aging effect of loss of material due to corrosion for steel piles exposed to groundwater/soil environment. The time-limited aging analyses (TLAA) described in SLRA Section 4.7.6 is credited for all table 2 items associated with AMR Item 3.5.1-079, except for those for Switchyard and Transformers (SLRA Table 3.5.2-26), which are managed by the SMP.

SLRA does not make clear why aging effects of piles for Switchyard and Transformers are managed by the SMP while others are managed by the TLAA. SLRA also does not make clear the difference of piles managed by the different programs.

3. Clarify the differences between the steel piles addressed by TLAA in SLRA Section 4.7.6 and those managed by the SMP.
4. Explain why the SMP is used to address the aging effect of loss of material due to corrosion for the steel piles of Switchyard and Transformers while other piles are managed by the TLAA.

9 Table 3.5.2-16 3-

1022, 3-1023 AMR Item 3.5.1-088 (NUREG-2191 Item, III.A6.TP-261) addresses the aging effect of loss of preload due to self-loosening for structural bolting exposed to any environment. However, for Intake Structure in SLRA Table 3.5.2-16, AMR Item 3.5.1-088 is applied to steel elements (beams, columns, baseplates, bracing, stairs, platforms, grating, decking, ladders and embedded steel), which has different aging effect than loss of preload.

It appears that SLRA uses incorrect Table 1 AMR items for steel elements in SLRA Table 3.5.2-16.

Clarify what Table 1 AMR Item and associated aging effects are applicable to steel elements (beams, columns, baseplates, bracing, stairs, platforms, grating, decking, ladders and embedded steel) of Intake Structure in SLRA Table 3.5.2-16.

10 B2.1.34 B-205 AR 01990963 documents significant boric acid leakages observed in multiple areas of the Waste Gas Decay Tanks (WGDT) room located below the spent fuel pool. The action report details the presence of dry white boric acid deposits on the WGDT room ceiling and the subsequent corrective Operating Experience (Boric Acid Attack of Concrete):

5. Discuss the operating history related to boric acid attack on reinforced concrete in the SFP, Fuel Transfer Canal, and Refueling Cavity.

Include relevant documentation such as

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 78 actions taken, including cleaning and enhancements to inspection procedures. Attachment 1 of AR 01990963 includes a WGDT room plan view that identifies eight locations with boric acid accumulation, along with associated photographic evidence.

OST-013, Weekly Checks and Operations, provides inspection procedures for LLD-11 and LLD-12 (Spent Fuel Pit Leak Detection Header 1 and Header 2 Isolation). This procedure includes sampling from LLD-11 and LLD-12 for isotopic and boron analysis.

EPRI Technical Report 3002007348 (2016) presents a recommended AMP template for managing boric acid attack on the reinforced concrete structures exposed to leakage from spent fuel pools. This guidance aligns with the Branch Technical Position RLSB-1 in SRP-SLR, Appendix A.1. The aging management approaches implemented by facilities such as Comanche Peak Nuclear Power Plant (CPNPP) and Diablo Canyon Power Plant (DCPP) in their SLRAs are consistent with this EPRI guidance.

The applicant is requested to follow the guidance in EPRI 3002007348 to adequately manage aging effects of boric acid attack on the reinforced concrete in the spent fuel pool (SFP), the Fuel Transfer Canal, and the Refueling Cavity during the SPEO.

photographs, inspection or testing data, results of boroscopic examinations, and a summary of corrective actions taken.

6. Explain how the aging effects of boric acid attack on reinforced concrete structures in the SFP, Transfer Canal, and Refueling Cavity have been managed over the past 10 years.
7. Review each of the seven elements of the aging management program template provided in EPRI report 3002007348, and identify any enhancements required to the existing RNP Structures Monitoring AMP to ensure effective management of boric acid attack on reinforced concrete in the SFP, Transfer Canal, and Refueling Cavity. Provide detailed descriptions of these enhancements, if any.
8. Provide a technical justification for why enhancements to certain elements (1 through
7) of the existing RNP Structures Monitoring AMP, as compared to the EPRI report 3002007348 AMP template, are not necessary. The justification should be supported by applicable plant procedures, OE, inspection and test results, or other relevant documentation demonstrating that the current program effectively manages the aging effects of boric acid attack on reinforced concrete.

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 79 RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants Question Number SLRA Section SLRA Page Background / Issue Discussion Question / Request 1

B2.1.35 B-213 GALL-SLR Report,Section XI.S7, 4. Detection of Aging Effects, states that submerged structural elements are visually inspected (e.g., dewatering, divers) at least once every 5 years. However, such a provision is not found in the SLRA, basis document, or the implementing procedure provided in the e-Portal.

Detection of Aging Effects:

Provide the implementing procedure that indicates that the submerged structural elements are visually inspected (e.g., dewatering, divers) at least once every 5 years.

Non-EQ Electrical Cable and Connection Insulation Material Question Number SLRA Section SLRA Page Background / Issue Discussion Question / Request 1

B.2.1.37 B -

222 NUREG 2191 XI.E1 Program Description states:

Adverse localized environments (ALE) are identified using an integrated approach. This approach includes, but is not limited to: (a) the review of EQ program radiation levels, temperatures, and moisture levels; (b) recorded information from equipment or plant instrumentation; (c) as-built and field walk down data (e.g., cable routing data base);

(d) a plant spaces scoping and screening methodology; and (e) the review of relevant plant-specific and industry OE.

The staff notes that the program description in Robinson SLRA section B2.1.37 and the basis Provide a description of the method of identifying ALEs at Robinson and include it in SLRA section B2.1.37 and the basis document SLR-RNP-AMPR-XI.E1.

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 80 document SLR-RNP-AMPR-XI.E1 Rev 1 appear not to include the method of identifying the ALEs at Robinson.

2 SLRA B2.1.37 B -

222 NUREG 2191 AMP XI.E1, Program Description, states: Accessible in-scope cable and connection inspection is considered a visual inspection performed from the floor, with the use of scaffolding as available, without the opening of junction boxes, pull boxes, or terminal boxes. The purpose of the visual inspection is to identify ALE (employing diagnostic tools such as thermography as applicable). These potential ALE are then evaluated, which may require further inspection using scaffolding or other means (e.g., opening of junction boxes, pull boxes, accessible pull points, panels, terminal boxes, and junction boxes) to assess cable and connector electrical insulation aging degradation.

SLRA section B2.1.37, Program Description states:

The Electrical Insulation for Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification (EQ) Requirements aging management program is an existing condition monitoring program that will continue to manage the aging effect of reduced insulation resistance of accessible non-EQ electrical cable and connection insulation in adverse localized environments.

Robinson Document AD-EG-RNP-1615, Cable Aging Management Program, Revision 0, and AD-EG-ALL-1615, Cable Aging Management Program-Implementation, Revision 5 states: Accessible:

Capable of being reached quickly for operation,

1. Clarify if scaffolding may be used to inspect accessible cables and connections consistent with NUREG 2191 AMP XI.E1. If so, include the possibility of using scaffolding in for consistency with NUREG 2191 AMP XI.E1 and the basis document SLR-RNP-AMPR-XI.E1. If not, explain why.
2. Clarify if scaffolding or other means (e.g., opening of junction boxes, pull boxes, accessible pull points, panels, terminal boxes, and junction boxes) can be used to assess cable and connector electrical insulation aging degradation in potential ALEs. If so, include the possibility of using scaffolding or other means to assess cable and connections insulation aging in potential ALEs for consistency with NUREG 2191 AMP XI.E1 and the basis document SLR-RNP-AMPR-XI.E1. If not, explain why.

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 81 renewal, or inspection, without requiring those to whom ready access is requisite to climb over or remove obstacles or to resort to portable ladders, etc. Cables and connections that can be approached and viewed easily without the opening of junction boxes or control panels are considered accessible.

NUREG 2191 AMP XI.E1, Program Description, states: Accessible in-scope cable and connection inspection is considered a visual inspection performed from the floor, with the use of scaffolding as available, without the opening of junction boxes, pull boxes, or terminal boxes. The purpose of the visual inspection is to identify ALE (employing diagnostic tools such as thermography as applicable). These potential ALE are then evaluated, which may require further inspection using scaffolding or other means (e.g., opening of junction boxes, pull boxes, accessible pull points, panels, terminal boxes, and junction boxes) to assess cable and connector electrical insulation aging degradation.

The staff notes that the SLRA section B2.1.37 and the basis document SLR-RNP-AMPR-XI.E1 Rev 1 do not describe what is considered an accessible cable inspection. Also, there is a discrepancy between the inspection of accessible cable and connection in NUREG 2191 AMP XI.E1 and the definition of accessible in Robinson Document AD-EG-RNP-1615.

3 B2.1.37 B -

NUREG 2191 X1.E1 Parameters Monitored or Inspected element states: An adverse localized

9. For consistency with NUREG 2191 X1.E1, 1) define the most limiting temperature, radiation,

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 82 222 environment is a plant-specific condition; therefore, the applicant should clearly define the most limiting temperature, radiation, and moisture environments and their basis. The applicant should also inspect for ALEs for each of the most limiting cable and connection electrical insulation plant environments (e.g., caused by temperature, radiation, moisture, or contamination).

Robinson basis document SLR-RNP-AMPR-XI.E1 Rev 1, Parameters Monitored or Inspected element states that this program element will be consistent with the recommendations of NUREG-2191, AMP XI.E1, element 3, Parameters Monitored or Inspected, with the enhancement referenced in the document.

The staff notes that Robinson basis document SLR-RNP-AMPR-XI.E1 Rev 1, Parameters Monitored or Inspected element appears not to 1) define the most limiting temperature, radiation, and moisture environments and their basis, and 2) state if Robinson will inspect for ALEs for each of the most limiting cable and connection electrical insulation plant environments (e.g., caused by temperature, radiation, moisture, or contamination).

and moisture environments and their basis, and

2) clarify if Robinson will inspect for ALEs for each of the most limiting cable and connection electrical insulation plant environments (e.g.,

caused by temperature, radiation, moisture, or contamination).

10. Provide the document(s) where the above requested information will be added and include the inspection for ALEs for each of the most limiting cable and connection electrical insulation plant environments (e.g., caused by temperature, radiation, moisture, or contamination) in the SLRA section B2.1.37 and the basis document SLR-RNP-AMPR-XI.E1.

Indicate if this inspection is an enhancement to the existing program or not.

4 B2.1.37 B -

222 NUREG 2191 AMP XI.E1 Detection of Aging Effects element states: Cable and connection insulation are evaluated to confirm that the dispositioned corrective actions continue to support in-scope cable and connection intended functions during the subsequent period of extended operation.

The staff notes that Robinson Program basis

1. Clarify if Robinson will evaluate the Cable and connection insulation to confirm that the dispositioned corrective actions continue to support in-scope cable and connection intended functions during the SPEO.
2. Clarify if the above-mentioned action in the Detection of Aging Effects element is an enhancement to the existing program and include this action in the SLR-

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 83 document SLR-RNP-AMPR-XI.E1 Rev 1, Detection of Aging Effects element appears not to include the evaluation of cable and connection insulation to confirm that the dispositioned corrective actions continue to support in-scope cable and connection intended functions during the SPEO.

RNP-AMPR-XI.E1 for consistency with NUREG 2191 AMP XI.E1.

5 B2.1.37 B -

222 In Robinson WO 1126106-02, it is stated As noted throughout UFSAR Section 9.5.1B and 8.3.3, most all trays containing engine safeguards cable with PVC jackets had flame retardant mastic coating applied. Therefore, most all equipment referenced in EGR-NGGC-0507 located in the Reactor Auxiliary Building and Control Complex Building has flame retardant coating and is not visible for inspection.

NUREG 2191 AMP XI.E1, Detection of Aging Effects element states: The inspection of accessible cable and connection insulation material is used to evaluate the adequacy of inaccessible cable and connection electrical insulation. NUREG 2191 AMP XI.E1, Corrective Actions element states:

When an unacceptable condition or situation is identified, a determination is made as to whether the same condition or situation is applicable to additional in-scope accessible and inaccessible cables or connections (extent of condition).

The staff notes that the cables inside the trays covered with flame-retardant coating are inaccessible, but they are not managed by Robinson AMP B2.1.39 for inaccessible medium voltage power cables, and they are not discussed in the basis document SLR-RNP-AMPR-XI.E1 Rev 1.

1. Provide a discussion on how the condition of cable jackets in trays covered with fire/flame retardant will be inspected with Robinson program B2.1.37.
2. Discuss how Robinson program B2.1.37 addressed NUREG 2191 AMP XI.E1 Corrective Actions element statement: When an unacceptable condition or situation is identified, a determination is made as to whether the same condition or situation is applicable to additional in-scope accessible and inaccessible cables or connections (extent of condition). Include this discussion in the basis document SLR-RNP-AMPR-XI.E1, Corrective Actions element for consistency with NUREG 2191 AMP XI.E1.

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 84 In addition, the SLRA section B2.1.37 and the basis document SLR-RNP-AMPR-XI.E1 Rev 1 do not discuss the above-mentioned extent of condition in NUREG 2191 AMP XI.E1 Corrective Actions.

Non-EQ Sensitive Instrumentation Cable Insulation Material Question Number SLRA Section SLRA Page Background / Issue Discussion Question /

Request 1

B2.1.38 B -

227 NUREG 2191 AMP XI.E2, Program Description states: A discussion of adverse localized environments and methods of identifying them can be found in Generic Aging Lessons Learned for Subsequent License Renewal (GALL-SLR) Report AMP XI.E1.

Robinson basis document SLR-RNP-AMPR-XI.E2 for SLRA section B2.1.28 refers to Oconee Nuclear Station (ONS) AMP for the description of the ALEs and their identification in the Scope of Program element.

The staff notes that Robinson basis document SLR-RNP-AMPR-XI.E1, Rev.1 describes the ALEs and should provide the identification of ALEs, and therefore, should be referenced in SLR-RNP-AMPR-XI.E2 for the ALEs and their identification.

Explain why SLR-RNP-AMPR-XI.E2 refers to ONS AMP instead of Robinson SLR-RNP-AMPR-XI.E1 for the description of the ALEs and their identification.

2 B2.1.38 B -

227 NUREG 2191 AMP XI.E2, Acceptance Criteria states: An unacceptable indication is defined as a noted condition or situation, if left unmanaged, could potentially lead to a loss of intended function.

Robinson basis document SLR-RNP-AMPR-XI.E2 did not provide a definition for an unacceptable indication because SLR-RNP-AMPR-XI.E2, Acceptance Criteria, does not used the term elsewhere in that section.

The staff notes that the term unacceptable conditions is used in the SLR-Provide the definition of an unacceptable conditions in the SLR-RNP-AMPR-XI.E2.

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 85 RNP-AMPR-XI.E2 Confirmatory Process: Identification of a potentially adverse trend due to recurring or repetitive unacceptable conditions will result in the initiation of an NCR.

Inaccessible Low-Voltage Cables Question Number SLRA Section SLRA Page Background / Issue Discussion Question / Request 1

3.6.2 Table 3.6.2-2, B2.1.41 3-

1095, B-242 SLRA Table 3.6.2-2 "Electrical and Instrumentation and Controls - Cable and Connections - Aging Management Evaluation" (page 3-1095) lists the note for Inaccessible Low-Voltage Power Cables as "Note A." Note A is defined as "Consistent with NUREG-2191 item for component, material, environment, and aging effect. AMP is consistent with NUREG-2191 AMP" (page 3-1102). In SLRA AMP B2.1.41 "Electrical Insulation for Inaccessible Low-Voltage Power Cables Not Subject To 10 CFR 50.49 Environmental Qualification Requirements," (page B-242) exceptions are taken to NUREG-2191 for Program Element 4 "Detection of Aging Effects" and Program Element 7 "Corrective Actions." The NUREG-2191 Consistency statement also states, in part, "The [aging management program] is a new program that, when implemented with exceptions below, will be consistent with NUREG-2191,Section XI.E3C".

Table 3.6.2-2 note B is defined as "Consistent with NUREG-2191 item for component, material, environment and aging effect. AMP takes some exceptions to NUREG-2191 AMP" (page 3-1102).

Clarify whether the Table 3.6.2-2 note is correct as listed for AMR ID 5323 "Electrical Conductor Insulation for Inaccessible Low-Voltage Power Cables," or should it be edited to indicate note B "Consistent with NUREG-2191 item for component, material, environment and aging effect. AMP takes some exceptions to NUREG-2191 AMP."

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 86 Metal Enclosed Bus Question Number SLRA Section SLRA Page Background / Issue Discussion Question / Request 1

B2.1.42 B -

247 NUREG 2191 AMP XI.E4 element 4, Detection of Aging Effects, states: When thermography is employed by the applicant, the applicant demonstrates with a documented evaluation that thermography is effective in identifying MEB increased resistance of connection (e.g., infrared viewing windows installed, or demonstrated test equipment capability).

The staff notes that SLRA AMP B2.1.42, Metal Enclosed Bus and associated documents on the e-Portal appear not to discuss how the thermography is effective in identifying Robinson MEB increased resistance of connection.

Discuss how the thermography is effective in identifying Robinson MEB increased resistance of connection, and provide the documented evaluation that was used to make that determination.

2 B2.1.42 B -

247 NUREG 2191 AMP XI.E4 Parameters monitored or inspected, states: MEBs are generally accessible structures and as such are inspected and tested in their entirety. However, depending on particular plant configurations, some segments of the MEB may be considered inaccessible due to close proximity to other permanent structures (e.g., nearby walls, ducts, cable trays, equipment or other structural elements).

For inaccessible MEB internal or external segments, the applicant demonstrates (e.g., through alternative analysis, inspection, test or plant OE) that the inaccessible MEB segments evaluation, together with the accessible MEB inspection and test program, will Does Robinson have any segments of the MEB that are considered inaccessible due to close proximity to other permanent structures? If so, discuss how Robinson demonstrated that the inaccessible MEB segments evaluation, together with the accessible MEB inspection and test program, will continue to maintain the MEB consistent with the current licensing basis during the SPEO, and include this discussion in the basis document SLR-RNP-AMPR-XI.E4 for consistency with NUREG 2191 AMP XI.E4.

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 87 continue to maintain the MEB consistent with the current licensing basis during the subsequent period of extended operation.

The staff notes that Robinson SLRA AMP B2.1.42 and associated basis document SLR-RNP-AMPR-XI.E4 appear not to include the above-quoted statements of NUREG 2191 AMP XI.E4.

Non-EQ Cable Connections Question Number SLRA Section SLRA Page Background / Issue Discussion Question / Request 1

B2.1.44 B-252 GALL-SLR XI.E6, "Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements" in discussing the one-time test of sample cable connections, the GALL-SLR directs "if an unacceptable condition or situation is identified in the selected sample, a determination is made as to whether the same condition or situation is applicable to other connections not tested. The corrective action program is used to evaluate the condition and determine appropriate corrective action."

SLRA B2.1.44 and SLR-RNP-AMPR-XI.E6 Revision 0 only describe, in part, the "representative sample of non-EQ cable connections within the scope of subsequent license renewal will be tested on a one-time test basis...", and further states "Depending on the one-time test results, subsequent testing may have to be performed within ten years of initial testing."

Does the SLRA B2.1.44 or SLR-RNP-AMPR-XI.E6 program require that "a determination to be made as to whether the same unacceptable condition or situation is applicable to other connections not tested" as required by the GALL-SLR? Where in the application or basis document, or program description is the requirement to make a determination whether the same unacceptable condition or situation is applicable to other connections not tested?

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 88 PWR Vessel Internals Question Number SLRA Section SLRA Page Background / Issue Discussion Question / Request 1

B2.1.7 B-53 SLRA B2.1.7, the Enhancement paragraph states that Robinson will incorporate the revisions to MRP-227 Revision 1-A, Tables 4-3, 4-6, 4-9, and 5-3 reported in the final NRC-approved version of MRP-227 Revision 2, into the Robinson PWR Vessel Internals program prior to entering the subsequent period of extended operation The above statement could be interpreted as incorporation into the Robinson PWR Vessel Internals AMP only the revisions to MRP-227, Revision 1-A, Tables 4-3, 4-6, 4-9 and 5-3 that are in the final NRC-approved version of MRP-227 Revision 2. However, the final NRC-approved version of MRP-227, Revision 2 may contain additional guidance in those tables than the revisions to those Tables of MRP-227, Revision 1-A. The staff noted that Tables 4-3, 4-6, 4-9 and 5-3 of NRC-approved version of MRP-227, Revision 2 should be incorporated in the subject AMP.

Also, NRC-approved MRP-227, Revision 2 contains additional guidance in addition to those tables.

The staff noted that the PWR Vessel Internal AMP of a SLR application should follow the relevant guidance in the latest NRC-approved version of MRP-227.

(a)Confirm that the Robinson PWR Vessel Internal AMP will be revised to incorporate and follow the relevant guidance in the NRC-approved MRP-227 Revision 2 (or the latest NRC-approved version).

(b) Discuss whether information is needed to supplement the Enhancement section of the subject AMP to respond to the staffs request.

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 89 2

B2.1.7 B-57 In OE #15, the applicant stated that The schedule for subsequent inspections of Flaws 1-5

[in the upper girth weld of the core barrel] shall be determined by the Robinson Inservice Inspection Program in accordance with ASME Section XI (a). The staff does not object that the applicant follow the ASME Code Section XI to examine the flaws in the upper girth weld of the core barrel even though the core barrel is not an ASME Code component. However, given this weld is not an ASME Code component, the staff is not clear regarding the examination frequency and examination method that will be used to examine the flaws in the upper girth weld of the core barrel.

Also, the examination frequency and method of the NRC-approved MRP-227, Revision 2 may be different from that of the ASME Code,Section XI, Table IWB-2500-1.

(b) The staff is not clear which examination frequency and method the applicant will follow to examine RPV internal components if the examination frequency and examination method are different between MRP-227 (latest NRC-approved revision) and the ASME Code,Section XI, Table IWB-2500-1.

(a) Describe the examination frequency and examination method that will be used to examine the flaws in the upper girth weld of the core barrel in the future.

(a1) Discuss whether information is needed to supplement OE #15 of the subject AMP to respond to the staffs request.

(b) Discuss the examination frequency and examination method will be used to examine RPV internal components in the future if the examination frequency and examination method are different between NRC-approved MRP-227, Revision 2 (or the latest NRC-approved revision) and the ASME Code,Section XI, Table IWB-2500-1.

(b1) Discuss whether information is needed to supplement the subject AMP to respond to the staffs request.

3 2.1.7 n/a Section 3.2 of NEI 14-12, Aging Management Program Effectiveness, (ML15090A665),

recommends that utility self-assess the effectiveness of AMPs at five-year intervals.

(a)Confirm that the applicant will assess the effectiveness of the Robinson PWR Vessel Internals AMP at least every five years in accordance with NEI 14-12.

(b) Discuss whether information is needed to supplement the subject AMP to respond to the staffs

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 90 request.

4 B2.1.7 B-53 Section B2.1.7, Enhancement paragraph states that The following enhancement(s) will be implemented to the following program element(s):

Detection of Aging Effects (Element 4) and Acceptance Criteria (Element 6). The PWR Vessel Internals aging management program will be updated as necessary to provide guidance for implementing the changes to primary and expansion items in MRP-227, Rev 1-A, Tables 4-3, 4-6, 4-9 (and Table 5-3 for Element 6 only) as supplemented by MRP 2023-005, [ML23290A020, Rev 0] Revision 01, MRP 2024-008, and the Robinson gap analysis. The Robinson gap analysis concluded that the primary and expansion items reported in MRP-227, Rev 2 Tables 4-3, 4-6, 4-9 (and Table 5-3 for Element 6 only) as supplemented by MRP 2023-005, Revision 01 and MRP 2024-008 are sufficient for the subsequent period of extended operation (a)The staff noted that Table 5-3 of MRP-227, Revision 1-A and Revision 2 contains acceptance criteria (Element 6) and expansion criteria, but the applicant only mentioned updating the subject AMP based on Element 6 of Table 5-3. The staff is not clear why the subject AMP will not be updated based on the expansion criteria in Table 5-3.

(b). The staff noted that the contents in Table 5-3 in MRP-227, Revision 1-A and in Revision 2 are different. Therefore, the staff is not clear whether the Robinson PWR Vessel Internals AMP will be consistent with Table 5-3 in MRP-227, Rev 1-A or (a)Explain why the subject AMP will be updated based on Element 6 in Table 5-3 only and not also based on the expansion criteria in Table 5-3.

(b) Clarify whether referenced Table 5-3 will be from MRP-227, Revision 1-A or from NRC-approved MRP-227, Revision 2.

(c) Discuss whether supplemental information to the Enhancement Section of the subject AMP is needed to respond to the staffs requests in (a) and (b) above.

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 91 with NRC-approved MRP-227, Rev 2.

5 B2.1.7 B-53 to B-58 SLRA B 2.1.7, Operating Experience Section describes the degradation of several RPV internal components that were inspected during the 2022 refueling outage. The staff is not clear whether all the in-scope RPV internal components have been inspected during the 2022 refueling outage.

(a)Identify in-scope RPV internal components that have NOT been inspected to date per the guidelines in MRP-227-A, MRP-227, Rev 1-A, any industry interim guidance, and ASME Code,Section XI, Table IWB-2500-1. The staff noted that at the present the NRC has not approved generic use of MRP-227, Revision 2 (b) Discuss whether all the in-scope RPV internal components will be examined during the sixth 10-year in-service inspection interval prior to entering the SPEO.

(c) Discuss whether supplemental information to the OE Section of the subject AMP is needed to respond to the staffs requests in (a) and (b) above.

6 B2.1.7 B-53 SLRA B2.1.7, Enhancement Section states that Robinson will incorporate the revisions to MRP-227 Revision 1-A, Tables 4-3, 4-6, 4-9, and 5-3 reported in the final NRC-approved version of MRP-227, Revision 2, into the Robinson PWR Vessel Internals program prior to entering the SPEO.

(a)The staff is not clear whether the in-scope RPV internal components at Robinson are the same as or include more components than the components covered in Tables 4-3, 4-6, 4-9, and 5-3 of the NRC-approved MRP-227, Revision 2.

(a) Identify any in-scope Robinson RPV internal components that are not included in Tables 4-3, 4-6, 4-9, and 5-3 of MRP-227 Revision 1-A or Revision 2.

If they exist, discuss how those in-scope RPV internal components will be examined during the SPEO.

(b) Discuss whether information is needed to supplement the Enhancement Section of the subject AMP to respond to the staffs request.

Flow-Accelerated Corrosion

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 92 Question Number SLRA Section SLRA Page Background / Issue Discussion Question / Request 1

B2.1.8 SLRA p2048 (Table 3.4.2-1 for Aux Boiler/Steam System)

BP-2022-0001-02-TR, Erosion Susceptibility Analysis (ESA) states the Auxiliary Boiler/Steam System (AS) is excluded from erosion review by Robinson Engineering. (p35/258) Note 2 of SLRA Table 3.4.2-1 states that erosion susceptibility is determined by susceptibility analyses, OE, or system design. The staff notes that AMR Item 3.4.1-060 addresses erosion with note 2.

11. What OpEx prompted the need to manage erosion with item 3.4.1-060 in SLRA Table 3.4.2-1? Provide applicable ARs.
12. How many locations are being inspected in the AS system and were any locations determined through extent of condition (EoC) evaluations? If so, provide applicable EoC.
13. Assuming there is erosion OpEx for this system, provide the bases for excluding the AS system from the ESA.

2 B2.1.8 (OpEx

1)

SLRA pp 1644-45 BP-2022-0001-02-TR, Erosion Susceptibility Analysis (ESA), Section 7.4.22 notes that the Relevant OE field contains references to any relevant plant or industry operating experience.

This column includes numerous citations to EPRI 3002008124, Field Guide: Flow Accelerated Corrosion and Erosion, with comments discussing potential for erosion based upon industry OE. The EPRI report shows multiple examples of cavitation or droplet impingement for recirc piping in several systems.

However, the ESA predominantly says recirc piping is not susceptible to erosion either because the P&ID shows normally closed valves, or infrequent system operation. The staff notes that although valves in minimum-flow lines are normally closed, the line may still see significant wall thinning. In addition, the staff

14. Discuss whether the ESA has comprehensively included relevant industry OpEx for all recirc or min-flow lines. Specifically address the absence of relevant industry OpEx for the auxiliary feedwater min-flow lines.
15. Should SLRA Table 3.4.2-2 include an item for wall thinning due to erosion? If not, why not. If so, discuss whether the ESA should reflect the erosion potential.

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 93 notes that the industry OpEx database includes multiple examples of min-flow (recirc) piping erosion in auxiliary feedwater piping; however, SLRA Table 3.4.2-2, Aux Feedwater, does not include an AMR Item for erosion.

3 B2.1.8 SLRA page 1079 AMR Item 3.4.1-060 manages erosion for steel.

The staff notes that the SLRA cites this item in Table 3.4.2-4. The SLRA section B2.1.8 states that Robinson is managed by a Fleet Program at Duke and is based off the Oconee Safety Evaluation. Oconee implemented a plant-specific note to clarify that steel includes both carbon steel and gray cast iron. Robinson in Appendix B2.1.8 lists steel (carbon steel and gray cast iron) but then in Table 3.4.2-4 separates out other components into gray cast as its own material.

Is gray cast iron included in the definition of steel for the AMR 3.4.1-060?

4 B2.1.8 SLRA page 1079 and 1082 The SLRA cites AMR 3.4.1-060 in Table 3.4.2-4 Condensate System. This item is for steel material. The SLRA section B2.1.8 states that Robinson is managed by a Fleet Program at Duke and is based off the Oconee Safety Evaluation. Oconee addressed copper alloy in the flow-accelerated corrosion (FAC) program for erosion.

Are the copper alloy valve bodies in Table 3.4.2-4 susceptible to erosion?

5 B2.1.8 AD-EG-ALL-1610 Flow-Accelerated Corrosion Implementation, Rev 7, Section 5.8.3 states Components suspected to be wearing from an erosive mechanism shall use a safety factor of 2.0 when calculating the next scheduled Discuss apparent discrepancy between implementing procedure AD-EG-ALL-1610 for using safety factor of 2.0 in erosion evaluations versus using a safety factor of 1.1 for erosion components in R2R33 and R2R34.

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 94 inspection. Component MS009-A L90 is made from P22 material, so any wear would be due to erosion and not FAC. The data analysis for MS009-A-L90 from R2R33 (p240/530) and R2R34 for MS009-D (p242/529) show that a safety factor of 1.1 was used.

6 B2.1.8 There are portions of the heater drain tank that are not marked for erosion susceptibility in the ESA. However, the piping downstream of the flow control valve 1530B appears to be marked as susceptible to erosion in the ESA due to localized cavitation potential. The R2R32 Outage report notes the system had erosion OE.

Why doesnt the ESA site plant-specific OpEx?

7 B2.1.8 The ESA classifies Line MS-9 as not susceptible to erosion because fluid operating conditions are not conducive to erosion mechanisms. However, R2R32 and R2R33 discuss line MS-9 as being susceptible to erosion.

Discuss how plant-specific OE was considered during the development of the ESA. Specifically address why OE for MS-9 does not appear to be included in the ESA.

8 At Robinson, CSD-EG-ALL-1610-05, Erosion Degradation Mechanisms, Rev 0 states "Systems not susceptible to FAC are not within the scope of this document. This document refers to EPRI 3002005530, Recommendations of an Effective Program Against Erosive Attack, and (consistent with the EPRI guidance) states that a safety factor shall not be less than 2.0, for erosion component evaluations due in part to erosive wear being nonlinear. The cited EPRI guidance states "Note that unlike earlier work in Provide information to demonstrate that component erosion evaluations will use a safety factor of at least 2.0, for determining fitness for continued service and reinspection intervals, being performed by aging management programs other than the Flow-Accelerated Corrosion program (e.g., Closed Treated Water Systems, Open-Cycle Cooling Water System), or provide technical bases to justify why industry guidance does not need to be followed for component erosion evaluations in non-FAC susceptible

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 95 this area, system coverage is not limited to FAC-susceptible systems. Rather, all plant systems are included."

SLR-RNP-AMPR-XI.M17, Flow-Accelerated Corrosion AMP Evaluation Report, Rev 0 states that erosion in non-FAC susceptible systems are generally managed via other AMPs and that at Robinson, erosion in the component cooling water system piping is managed by the Closed Treated Water System program (XI.M21A), and erosion in the CCW heat exchangers is managed by the Open-Cycle Cooling Water System program (XI.M20).

Because Robinson's CSD-EG-ALL-1610-05, Erosion Degradation Mechanisms, only applies to FAC susceptible systems, and erosion in non-FAC susceptible systems is being managed by programs other that the Flow-Accelerated Corrosion program, it is not clear whether erosion component evaluations, for determining fitness for continued service and reinspection intervals, being performed outside of the FAC program, will use a safety factor of at least 2.0, as provided in the EPRI 300200553.

systems.

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 96 Fatigue Monitoring Program, GALL X.M1 Question Number SLRA Section SLRA Page Background / Issue Discussion Question / Request 1

B3.1 B-258 SLRA Section B3.1 addresses Enhancement 1 of the Fatigue Monitoring AMP. Specifically, the enhancement states that the program will be enhanced to require monitoring and tracking of transient cycles associated with the ASME Code,Section XI, Appendix L analysis be performed between the inspections for each ASME Code,Section XI, Appendix L locations.

In comparison, the OE section in SLRA Section B3.1 indicates that for subsequent license renewal (SLR),

thermal stratification of the pressurizer spray line and the effects of fatigue and environmentally assisted fatigue (EAF) were evaluated. The OE section also explains that this location has been included in the Fatigue Monitoring AMP and has been dispositioned with an ASME Code Section XI Appendix L flaw tolerance evaluation.

In contrast, the pressurizer spray line is not discussed in SLRA Section 4.3.4 that addresses the EAF analysis and related Appendix L flaw tolerance analysis. In addition, SLRA Table 4.3.4-1 does not identify the pressurizer spray line as a component location that managed by using the Appendix L flaw tolerance analysis The staff needs the resolution of the potential inconsistency between SLRA Section B3.1 and SLRA Section 4.3.4 in terms of the use of the

16. Given the absence of the discussion on the pressurizer spray line in SLRA Section 4.3.4 and SLRA Table 4.3.4-1 addressing EAF, clarify whether the aging effect of EAF in the pressurizer spray line will be managed by using the Appendix L flaw tolerance analysis and Fatigue Monitoring AMP to ensure that the inspection frequency remains valid.
17. Describe the following items related to the Appendix L analysis for the pressurizer spray line: (1) the bounding (limiting) component location of the pressurizer spray line evaluated in the Appendix L analysis; (2) the allowable time period until the postulated crack growth reaches the maximum acceptable crack depth; (3) the time period between inspections to be applied for the SPEO; and (4) the explanation for why SLRA Section 4.3.4 and SLRA Table 4.3.4-1 do not discuss the pressurizer spray line.
18. Describe the AMP that will be used to conduct the inspections on the pressurizer spray line to manage the cumulative fatigue damage due to EAF for the SPEO.

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 97 provisions in Appendix L to manage the aging effect of EAF in the pressurizer spray line.

2 B3.1 B-257 NRC Regulatory Issue Summary (RIS) 2011-14, Metal Fatigue Analysis Performed by Computer Software, addresses a potential concern regarding the methodology used by WESTEMS computer software in fatigue calculation and monitoring.

The RIS explains the methodology of the computer software may involve the algebraic summation of three orthogonal moment vectors, inconsistent with ASME Code,Section III, Subsection NB, Subarticle NB-3650, which indicates that the algebraic summation methodology is not an accurate representation of the resultant moment range.

In comparison, the OE section in SLRA Section B3.1 evaluates the OE related to the Fatigue Monitoring AMP. However, the OE section does not include the evaluation regarding RIS 2011-14.

The staff needs to confirm that the Fatigue Monitoring AMP does not have the concern addressed in RIS 2011-14.

19. Discuss the OE evaluation regarding the concern addressed in RIS 2011-14 to confirm that the Fatigue Monitoring AMP does not have such a concern. As part of the discussion, clarify whether the Fatigue Monitoring AMP uses the WESTEMS computer software for fatigue calculation and monitoring as applicable in accordance with ASME Code,Section III, Subsection NB.

3 B3.1 B-257 NRC RIS 2008-30, Fatigue Analysis of Nuclear Power Plant Components, addresses a potential concern regarding fatigue usage calculations that consider components response to a step change in temperature. 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. The RIS explains that the detailed stress analysis requires consideration of six stress

20. Discuss the OE evaluation regarding the concern addressed in RIS 2008-30 to confirm that the Fatigue Monitoring AMP does not have such a concern.

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 98 components, as discussed in ASME Code,Section III, Subsection NB, Subarticle NB-3200.

In comparison, the OE section in SLRA Section B3.1 evaluates the OE related to the Fatigue Monitoring AMP. However, the OE section does not include the evaluation regarding RIS 2008-30.

The staff needs to confirm that the Fatigue Monitoring AMP does not have the concern addressed in RIS 2008-30.

EQ of Electric Equipment Program, GALL X.E1 Question Number SLRA Section SLRA Page Background / Issue Discussion Question / Request 1

Table 3.6.2 Electrical and Instrumentation and Controls - Aging Management Evaluation 3-1094 AMR related to Item Number 3.6.1-001 of Table 3.6.1 is missing from Tables 3.6.2 Electrical and Instrumentation and Controls Aging Management Evaluation.

Table 3.6.1, "Summary of Aging Management Programs for Electrical and Instrumentation and Controls Evaluated in Chapter VI of the GALL-SLR Report," Item Number 3.6.1-001 discusses electrical equipment subject to 10 CFR 50.49 environmental qualification (EQ) requirements. However, none of the Tables 3.6.2-1 through 3.6.2-7 includes the Aging Management Evaluation for Electric equipment subject to 10 CFR 50.49 EQ requirements.

Item Number 3.6.1-001 for Electric equipment subject to 10 CFR 50.49 EQ requirements needs to be included into the Summary of Aging Management Evaluation Tables as described in Table B.1, "Equipment Subject to 10 CFR 50.49 Environmental Qualification Requirements." of the

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 99 GALL-SLR.

2 B3.3 B -

265 Clarification on which revision of EPRI Report NP-1558 is referenced in AD-EG-ALL-1612, Revision 8 document.

EPRI updated Report NP-1558, Revision 0 A Review of Aging Theory and Technology, dated September 1980 in July 2020 to address concerns with lack of or expired technical references for activation energies for certain materials. The NRC staffs understanding is that this revision resulted in up to 30% of activation energies being removed from the database.

During the Onsite Audit the staff asked the applicant if EQ components at Robinson used/relied upon EPRI Report NP-1558, Revision 0, as the justification/basis for activation energies for extending the qualified life of EQ equipment. The applicant stated that they have reviewed their EQ qualifications and found that, at Robinson, none of the EQ qualifications use the EPRI Report NP-1558, Revision 0.

While reviewing AD-EG-ALL-1612, Environmental Qualification (EQ) Program, Revision 8 the staff founds the applicant referenced EPRI Report NP-1558 in Section 5.3 for reevaluating materials for possible revisions to activation energy values. The document does not specify which version of the EPRI Report NP-1558 is used to perform this evaluation.

Therefore, the staff request clarification on which revision of the EPRI Report NP-1558 is used and referenced within AD-EG-ALL-1612.

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 100 Identification and Evaluation of Time-Limited Aging Analyses Question Number SLRA Section SLRA Page Background / Issue Discussion Question / Request 1

4.1 SLR-RNP-TLAA-0100, Revision 2 - contains applicant's basis document for TLAA identification SLRA Section 4.7.4 states, in part, for first license renewal, the Code Case N-481 fracture mechanics analysis of cast austenitic stainless steel (CASS)

RCP casings was a time-limited aging analysis and was utilized to manage reduction of fracture toughness by thermal embrittlement for the RCP casings.

SLRA Section 4.7.4 also states, in part, for SLR that the RCP casings and main flanges are not susceptible to thermal embrittlement and no additional measures beyond those required by ASME Section XI, Examination Category B-L-2, are required to manage thermal embrittlement of RCP items made from CASS for the SPEO, and that The TLAA identified for Code Case N-481 for management of thermal embrittlement for RCP casings is no longer applicable and is not a TLAA for SLR.

SLR-RNP-AMPR-XI.M12 - contains the applicant's basis document related to the Thermal Aging Embrittlement of CASS aging management program.

  1. 1 - Explain what changed, if anything, between initial license renewal (LR) and SLR such that the RCP casings are no longer susceptible to thermal aging.
  1. 2 - Were the CMTRs and design documentation/spec for the main flange operating temperature not readily available during initial LR to determine the susceptibly of the RCP casings to thermal aging?
  1. 3 - Was it intentional to conservatively address thermal aging of RCP pump casings during initial LR with the 60-year flaw tolerance evaluation analysis of the RCPs in accordance with ASME Code,Section XI, Code Case N-481, as reported in WCAP-15363, Revision 1.
  1. 4 - Confirm the flaw tolerance evaluation analysis of the RCPs in accordance with ASME Code,Section XI, Code Case N-481as reported in WCAP-15363, Revision 1 is not referenced/used/relied upon at all in the applicant's licensing basis.
  1. 5 - Plant basis document for TLAA identification indicated that Criteria 4 for the TLAA definition is not met. However, Criteria 2, 5 and 6 do not seem to apply to Robinson, Unit 2 as well - Does the applicant have any thoughts?

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 101 Upper-Shelf Energy Question Number SLRA Section SLRA Page Background / Issue Discussion Question / Request 1

4.2.2 SLRA Section 4.2.1 discusses the applicant's TLAA for neutron fluence projections for RPV beltline materials.

SLRA Section 4.2.2 discusses applicant's TLAA for Upper-Shelf Energy.

WCAP-18944-P, Revision 1 :H.B. Robinson Unit 2 Subsequent License Renewal: Reactor Vessel Upper-Shelf Energy Equivalent Margin Analysis" is referenced in the SLRA Section 4.2.2 to address the intermediate and upper shell plates with high sulfur content (> 0.018 wt%) and with 70 EFPY USE values below 50 ft-lbs using Regulatory Guide 1.99 Revision 2, Position 1.2. Specifically, the plates of interest include W10201-1, W10210-3, W10201-4, and W10201-5.

Section 1 ofWCAP-18944-P, Revision 1 indicates that the following RPV materials are addressed by the Equivalent Margins Analysis: intermediate shell plates, upper shell plates, RV inlet and outlet nozzle forgings, and nozzle-to-shell welds Confirm that the assessments/documentation contained throughout WCAP-18944-P, Revision 1 associated with the RV inlet and outlet nozzle forgings, and nozzle-to-shell welds are not relevant to the Upper-Shelf Energy TLAA in SLRA Section 4.2.2 and the associated disposition of 10 CFR 54.21(c)(1)(ii).

Confirm that the applicant understands that the staff's review of the EMA in WCAP-18944-P, Revision 1 for the Upper-Shelf Energy TLAA will not include the vRV inlet and outlet nozzle forgings, and nozzle-to-shell welds since the projected neutron fluence does not exceed the threshold in Appendix H to 10 CFR Part 50 based on the projections in SLRA Section 4.2.1.

2 Section 1 ofWCAP-18944-P, Revision 1 indicates that the following RPV materials are addressed by the Equivalent Margins Analysis: intermediate shell plates, upper shell plates, RV inlet and outlet nozzle forgings, and nozzle-to-shell welds

  1. 1 - Confirm that Table 4-9 of WCAP 18944, Revision 1, addresses the "Upper and Intermediate Shell Plates" and not the Nozzle Forging
  1. 1a - If yes, confirm the accuracy of the information presented in Table 4-9 of WCAP 18944, Revision 1

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 102 Table 4-9 of WCAP-18944-P, Revision 1 is labeled "K-5300 Tensile Instability Check for Nozzle Forgings Circumferential and Axial Flaws."

addresses the "Upper and Intermediate Shell Plates". Otherwise, explain and address discrepancy of information.

  1. 1b - If no, provide the information that address K-5300 Tensile Instability Check for the "Upper and Intermediate Shell Plates."

3 4.2.2 WCAP-18944-P, Revision 1 :H.B. Robinson Unit 2 Subsequent License Renewal: Reactor Vessel Upper-Shelf Energy Equivalent Margin Analysis" is referenced in the SLRA Section 4.2.2 to address the intermediate and upper shell plates with high sulfur content (> 0.018 wt%) and with 70 EFPY USE values below 50 ft-lbs using Regulatory Guide 1.99 Revision 2, Position 1.2. Specifically, the plates of interest include W10201-1, W10210-3, W10201-4, and W10201-5.

Section 3.2.3 ofWCAP-18944-P, Revision 1 provides the details for the J-integral resistance model for the Reactor Vessel Upper/Intermediate Shell Plates The discussion for "Levels A/B" regarding the use of mean values minus 2 sigma appears to be inconsistent with the information presented in Table 3-8 and Appendix A (Table A7-3)

Footnote 1 of Table 3-8 appears to be inconsistent with the information presented in Appendix A (Table A2-1b)

To ensure accuracy for the staff's SE:

  1. 1-Clarify whether mean values minus 2 sigma or lower bound values were used to assess Levels A/B for the EMA of the Reactor Vessel Upper/Intermediate Shell Plates.
  1. 2 - Confirm whether the information presented in Table 3-8 and Appendix A (Table A2-1b) as it relates to Footnote 1 of Table 3-8 is accurate. If not, discuss/justify the discrepancy.

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 103 Pressurized Thermal Shock Question Number SLRA Section SLRA Page Background / Issue Discussion Question / Request 1

4.2.3 SLRA Section 4.2.3 contains the TLAA for pressurized thermal shock.

SLRA Table 4.2.3-1 contains the material property information for the Robinson Unit 2 RPV materials, and indicates that the "Material properties consistent with RVID2 database."

RVID stands for Reactor Vessel Integrity Database Version 2.0.1 is located at the following link:

https://www.nrc.gov/reactors/operating/ops-experience/reactor-vessel-integrity/database-overview.html The staff noted that the following disclaimer is provided for RVID -

"This consolidated source of information is intended to be used as a general reference only. This information is not certified to be accurate or current, and has not been updated since July 2000."

SLRA Table 4.2.3-1 does not provide the specific Cu% and Ni% for each RPV material, but the chemistry factor is provided. WCAP-18766-NP Rev 1 (on the applicant's e-Portal) provides the Cu%

and Ni%, as well as the chemistry factor.

With respect to the following RPV Materials - the staff noted that the chemistry factor and Ni% identified in SLRA Section 4.2.3 andWCAP-18766-NP Rev 1 are inconsistent with RVID (i.e.,

SLRA/WCAP slightly non-conservative in comparison to RVID).

  • Upper Shell Axial Welds 1-273 A, B, & C
  • Intermediate Shell Axial Welds 2-273 A, B, & C
  • Lower Shell Axial Welds 3-273 A, B, & C The staff acknowledges that the differences in chemistry factor and Ni%

are small but are still in the non-conservative direction, and are in revision to the applicant's current licensing basis. Additionally, the staff acknowledges that the variation in chemistry factor is likely the direct result of the difference in Ni%. However, other than for these RPV materials listed below, the material prosperities for the remaining RPV materials are consistent with RVID and/or current licensing basis (CLB) documents; thus, the basis for the discrepancies is not clear/apparent.

Explain the slight differences in chemistry factor and Ni%, compared to RVID for the following RPV materials:

  • Upper Shell Axial Welds 1-273 A, B, & C
  • Intermediate Shell Axial Welds 2-273 A, B, & C
  • Lower Shell Axial Welds 3-273 A, B, & C Provide/reference any supporting basis for these changes/revisions

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 104 Pressure-Temperature Limits Question Number SLRA Section SLRA Page Background / Issue Discussion Question / Request 1

4.2.4 and 4.2.5 SLRA Section 4.2.4 states, in part, the 70 EFPY P-T limits were developed using the analytical methods and flaw acceptance criteria of WCAP-14040-A, Revision 4 and the ASME Code Section XI, Appendix G (1998 Edition through 2000 Addenda Edition),

which permits use of KIc. In addition, unirradiated To for weld 10-273 (Heat # W5214) was used to develop the 70 EFPY P-T limits as permitted by ASME Section III (2019 Edition), NB-2331 (a)(5). Irradiated To values for upper shell plate W10201-1 and weld 10-273 were not used for this demonstration effort. It was confirmed that Robinson will have sufficient operating windows to conduct heatups and cooldowns at 70 EFPY.

SLRA Section 4.2.5 states, in part, The low temperature overpressure (LTOP) enable temperature has been determined for 70 EFPY in accordance with the requirements of ASME Section XI, Appendix G and is 247.0 °F, which is below the current Technical Specification requirement of less than 350°F. The enable temperature is developed based on use of the RTT0 (initial RTNDT) for weld W5214 reported in Section 4.2.3; irradiated RTT0 for plate W10201-1 was not used.

SLRA Section A4.2.4 states, in part, based on establishment of unirradiated To for weld W5214 and irradiated To for upper shell plate W10201-1, Duke has determined that the current 46.3 EFPY P-T limits

  1. 1 - Address/discuss the discrepancy on the discussion of irradiated T0 in the UFSAR Supplement for the P-T limits TLAA in Section A4.2.4 - which may cause/imply that the use of irradiated T0 is permitted in the applicant's licensing basis following an approval of SLR without being granted an exemption in accordance with 10 CFR 50.12 (see ML24353A347 for explanation on basis that use of irradiated T0 would necessitate an exemption).
  1. 2 - Discussion topic for breakout session (written response optional) - SLRA Sections 4.2.4, 4.2.5, A4.2.4 and A4.2.5 indicate that the applicant has completed assessment to develop 70 EFPY P-T limits and LTOP enable temperature has been determined for 70 EFPY; however, both TLAAs are dispositioned in accordance with 10 CFR 54.21(c)(1)(iii) such that revisions in the technical specifications will be submitted to the NRC for approval prior to exceeding the period of applicability (i.e., 10 CFR 50.90 - license amendment request/review process). The staff noted this applicant assessment will not be reviewed based on the (iii) disposition of the TLAAs and will be subject to NRC review at the time of the future licensing action under 10 CFR 50.90.
  1. 3 - The disposition of the LTOP TLAA is identified as 10 CFR 50.54(c)(1)(iii) in SLRA Section A4.2.5 -

Accuracy is important given that the UFSAR Supplement would be incorporated in the applicant's

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 105 will be applicable to 70 EFPY and thus demonstrates that Robinson will be able to conduct heatups and cooldowns at 80 years. Additionally, the disposition of this TLAA is in accordance with 10 CFR 54.21(c)(1)(iii) - such that the pressure-temperature limits will be updated through the 10 CFR 50.90 process at a later, more appropriate date.

SLRA Section A2.4.5 states, in part, the low temperature overpressure enable temperature has been determined for 70 EFPY in accordance with the requirements of ASME Section XI, Appendix G and is 247°F, which is below the current Technical Specification requirement of 350°F. Additionally, the disposition of this TLAA is in accordance with 10 CFR 50.54(c)(1)(iii) - such that the pressure-temperature limits will be updated through the 10 CFR 50.90 process at a later, more appropriate date.

licensing basis. Please address the discrepancy and discuss whether a revision to the SLRA is necessary.

Metal Fatigue, TLAA 4.3 Question Number SLRA Section SLRA Page Background / Issue Discussion Question / Request 1

Table 3.1.1, Item 3.1.1-009; Table 3.1.2-1, AMR IDs 9053 and 9054; Sections 3.1.2.2.1 and 4.3 3-42, 3-106, 3-19, 4-36 SLRA Table 3.1.1, Item 3.1.1-009 describes the AMR results for stainless steel, steel, nickel alloy reactor coolant pressure boundary piping, piping components that are subject to cumulative fatigue damage and managed by using fatigue TLAAs described in SLRA Section 4.3.

The applicants AMR evaluation for AMR Item 3.1.1-009 is also described in SLRA Section 3.1.2.2.1. In

21. Clarify which subsection of SLRA Section 4.3 addresses the fatigue TLAAs for these Class 1 valve bodies that are described in the issue section in relation to AMR Item 3.1.1-009 (i.e., AMR IDs 9053 and 9054 in SLRA Table 3.1.2-1).

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 106 addition, SLRA Table 3.1.2-1, AMR IDs 9053 and 9054 describe the AMR results for the Class 1 valve bodies fabricated with stainless steel and CASS, respectively, which are associated with AMR Item 3.1.1-009.

However, it is not clear to the staff which subsection of SLRA Section 4.3 addresses the fatigue TLAAs for these Class 1 valve bodies.

22. In addition, discuss, if any, Class 1 valve bodies that have an existing cumulative usage factor analysis in the current licensing basis.

2 3.5.2.2.2.5 3-912 SLRA Section 3.5.2.2.2.5 addresses the applicants evaluation of the fatigue TLAAs involving time-dependent fatigue, cyclical loading or cyclical displacement of component support members, anchor bolts and welds for Groups B1.1, B1.2, and B1.3 component supports. The TLAA evaluation is associated with AMR Item 3.5.1-053.

SLRA Section 3.5.2.2.2.5 also indicates that the current licensing basis of H. B. Robinson Steam Electric Plant (RNP) contains no fatigue analysis for Group B1.1, B1.2 or B1.3 component supports.

In comparison, the staff noted that the fatigue TLAA for pressurizer components is addressed in SLRA Section 4.3.2.5. The staff needs clarification on whether pressurizer supports have an existing fatigue analysis that needs to be identified as a fatigue TLAA.

23. Clarify whether pressurizer supports have an existing fatigue analysis that needs to be identified as a fatigue TLAA.

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 107 (Site-Specific) Transient Cycle Projections for 80 Years Question Number SLRA Section SLRA Page Background / Issue Discussion Question / Request 1

4.3.1 4-37 SLRA Section 4.3.1 addresses the transient cycle projections for 80 years of operation. SLRA Section 4.3.1 explains that the maximum rate of transient cycle (occurrence) accumulation over a 10-year interval was used to extrapolate the projected number of future transient cycles beginning September 30, 2018, and ending at 80 years of operation.

In relation to the transient cycle projections and baseline 10-year cycle data (October 2008 -

September 2018), the meaning of the maximum rate of transient cycle accumulation is not clear to the staff.

24. In relation to the transient cycle projections and baseline 10-year cycle data, clarify the meaning of the maximum rate of transient cycle accumulation. As part of the discussion, explain how the maximum cycle accumulation rate for each transient is determined by using the baseline 10-year cycle data.

2 4.3.1 4-39 SLRA Table 4.3.1-1 describes the observed transient cycles up to September 30, 2018, and the 80-year projected cycles based on the observed cycles. The table also describes the design cycles (equivalent to original 40-year design cycles) for each transient and the percentage of design cycles for the 80-year projected cycles.

For the hydrostatic test - pressure 3110 psig, temperature 100 °F transient, SLRA Table 4.3.1-1 indicates the following: (1) the number of the observed transient cycles is zero and accordingly the number of 80-year projected cycles is zero; and (2) the number of design cycles is one (i.e.,

25. For the hydrostatic test - pressure 3110 psig, temperature 100 °F transient, resolve the apparent inconsistency between the 80-year projected cycles (i.e., zero projected cycle) and the percentage of design cycles for the 80-year projected cycles (i.e., 100 percent design cycles, which is equivalent to one cycle). As part of the discussion, clarify the following items: (1) whether the hydrostatic test transient occurred during the preservice testing or previous operation; and (2) whether the transient is expected to occur in the future operation.

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 108 one preoperational cycle).

In contrast, the SLRA table indicates that the percentage of design cycles for the 80-year projected cycles of the hydrostatic test transient is 100 percent suggesting that one cycle already may have occurred during the preservice testing or previous operation.

Therefore, the staff needs a resolution of the apparent inconsistency between the 80-year projected cycles (i.e., zero projected cycle for 80 years of operation) and the percentage of design cycles for the 80-year projected cycles (i.e., 100 percent design cycles, which is equivalent to one cycle) for the hydrostatic test transient.

3 4.3.1 4-39 The applicants fatigue monitoring procedure and fatigue TLAA evaluation document for SLR indicate that there is an existing fatigue analysis for reactor vessel internal baffle former bolts

(

References:

(1) PLP-109, Cycle and Transient Monitoring, Revision 13, Attachment 2, H.B.

Robinson Design Basis Transient Cycles, and (2)

SLR-RNP-TLAA-0300, Time-Limited Aging Analysis of Mechanical Systems Thermal Fatigue for Subsequent License Renewal, Revision 1, Attachment B, Transient Cycle Projections for 80 Years).

The fatigue monitoring procedure and fatigue TLAA evaluation document also indicate that the fatigue analysis of baffle former bolts and the associated fatigue monitoring include the following transients: (1) loss of load transient; (2) partial

26. Describe the observed (accumulated), 80-year projected and design cycles of the loss of load, partial loss of flow and loss of power (AC) transients, consistent with the format of SLRA Table 4.3.1-1. In addition, clarify whether the applicant will monitor these transients to manage the effect of fatigue for the baffle former bolts.
27. Explain why the existing fatigue analysis of the baffle former bolts is not discussed in SLRA Section 4.3.2.2 that addresses the fatigue analysis for reactor vessel internals. In addition, describe (1) the 80-year projected cumulative usage factor for the baffle former bolts and (2) a potential need to revise SLRA Section 4.3.2.2 and related AMR items, consistent with the existing fatigue analysis for the baffle former bolts.

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 109 loss of flow transient; and loss of power (AC) transients.

In contrast, SLRA Section 4.3.1 and Table 4.3.1-1 do not discuss these transients and the observed (accumulated), 80-year projected and current licensing basis design cycles of these transients.

In addition, the staff noted that the fatigue analysis of the baffle former bolts is not discussed in SLRA Section 4.3.2.2 that addresses the fatigue analysis for reactor vessel internals.

Class 1 Fatigue Analysis Question Number SLRA Section SLRA Page Background / Issue Discussion Question / Request 1

4.3.1.2 4-39 SLRA Section 4.3.2 addresses the fatigue analysis for Class 1 components. Specifically, the SLRA section discusses the fatigue analysis for the following components: (1) reactor vessel; (2) reactor vessel internals; (3) steam generators; (4) reactor coolant pumps; (5) pressurizer; (6) control rod drive mechanism; and (7) pressurizer surge line.

However, SLRA Section 4.3.2 does not discuss the 40-year (original design) and 80-year projected cumulative usage factor (CUF) values of the limiting locations of these components. The staff needs this information to confirm that there is reasonable assurance that the CUF values will

28. Describe the 40-year (original design) and 80-year projected CUF values of the limiting locations of the following components to ensure that there is reasonable assurance that the CUF values will continue to meet the design limit (1.0) for the SPEO: (1) reactor vessel; (2) reactor vessel internals (e.g., baffle former bolts); (3) steam generators; (4) reactor coolant pumps; (5) pressurizer; (6) control rod drive mechanism; and (7) pressurizer surge line.

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 110 continue to meet the design limit (1.0) for the SPEO.

2 4.3.2 4-41 SLRA Section 4.3.2.2 addresses the fatigue analysis for reactor vessel internals. The section explains that, although Westinghouse topical report, WCAP-10322, Revision 1 discusses a fatigue analysis for the hold-down spring and alignment pin, the analysis is not directly applicable to the H.B. Robinson Steam Electric Plant (RNP), Unit 2.

However, SLRA Section 4.3.2.2 does not clearly discuss the basis for why the fatigue analysis for the hold-down spring and alignment pin described in WCAP-10322, Revision 1 is not applicable to RNP Unit 2.

29. Clarify the basis for the fatigue analysis for the hold-down spring and alignment pin described in WCAP-10322, Revision 1 is not applicable to RNP Unit 2.
30. In addition, discuss the following items related to the fatigue analysis mentioned in the issue section to clarify the significance of fatigue in the hold-down spring and alignment pin: (1) CUF values for these components; (2) whether the design transient cycles evaluated in the fatigue analysis (WCAP-10322, Rev. 1) are bounding for the 80-year cycles at the Robinson plant; and (3) whether the loading/unloading transients are the major transients that contribute to the CUF values (in consideration that the Robinson plant is not load-following plant).

3 4.3.2.8 4-45 SLRA Section 4.3.2.8 addresses the Class 1 components for which fatigue waiver evaluations are applicable. The section explains that all pressurizer items with the exception of the surge and spray nozzles, lower head, instrument nozzle and heater wells are subject to fatigue waiver evaluations in accordance with ASME Code Section III, N-415.1.

The staff needs clarification as to specific examples of the pressurizer components subject to the fatigue waiver evaluations.

31. Describe specific examples of the pressurizer components subject to the fatigue waiver evaluations.

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 111 Non-Class 1 Piping Fatigue Analysis Question Number SLRA Section SLRA Page Background / Issue Discussion Question / Request 1

4.3.3 4-45 SLRA Section 4.3.4 addresses the fatigue TLAAs for the non-Class 1 piping systems (i.e., ANSI B31.1 piping systems). The TLAAs are also called the allowable stress analyses for the piping systems.

The TLAAs regarding allowable stress analyses rely on the implicit fatigue analysis provisions in the ANSI B31.1 code. These provisions allow no reduction in the allowable stress range for thermal expansion stresses if the number of equivalent full temperature cycles does not exceed 7000 cycles.

In addition, SLRA Table 4.3.3-2 describes the conservatively estimated 80-year projected cycles for the non-Class 1 piping systems.

However, SLRA Section 4.3.3 does not clearly describe how the 80-year projected cycles were determined (e.g., based on piping system design information, plant operation procedures, test requirements, UFSAR information and specific system-level knowledge).

32. Discuss how the 80-year projected cycles listed in SLRA Table 4.3.3-2 were determined (e.g., based on piping system design information, plant operation procedures, test requirements, UFSAR information and specific system-level knowledge).

2 4.3.3 4-47 SLRA Section 4.3.3 explains that the non-class 1 mechanical systems within the scope of SLR are often subject to continuous steady state operation such that operating temperatures only vary during operational transients. The section also indicates that reactor trips, heatups and cooldowns are

33. Clarify the meaning of the operational transients in relation to the non-Class 1 piping systems that are described in the issue section. As part of the discussion, clarify whether the operational transients are equivalent to the reactor coolant system transients.

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 112 included in these operational transients.

The meaning of the operational transients in relation to the non-Class 1 piping systems is not clear to the staff. The staff needs clarification on whether the operational transients are equivalent to the reactor coolant system transients.

In addition, SLRA Section 4.3.3 indicates that portions of the piping and piping components of non-Class 1 mechanical systems within the scope of SLR are operated in a manner that subjects them to thermal cycles. The section explains that the examples of those piping systems are auxiliary boiler/steam system, auxiliary feedwater system, and chemical and volume control system The meaning of the thermal cycles discussed above is not clear to the staff. The staff needs to clarify whether the thermal cycles are the cycles specifically applied to certain non-Class 1 piping systems or lines rather than the reactor coolant system transients that can affect multiple piping systems broadly.

34. Clarify the meaning of the thermal cycles that are described in the issue section. As part of the discussion, clarify whether the thermal cycles are the cycles specifically applied to certain non-Class 1 piping systems or lines rather than the reactor coolant system transients that can affect multiple piping systems broadly.

3 4.3.3 4-48 SLRA Table 4.3.3-2 describes the 80-year cycle projections for the non-Class 1 piping systems. For the auxiliary boiler/steam system, the table indicates that 24 cycles per year apply to the piping system and the total number of 80-year cycle projections is 2210 cycles.

Given that the number of cycles estimated with annual 24 cycles for 80 years is 1920 cycles (i.e.,

24 cycles/year x 80 years), the staff needs

35. Given that the number of cycles estimated with annual 24 cycles for 80 years is 1920 cycles (i.e.,

24 cycles/year x 80 years), clarify whether the applicants cycle projections for non-Class 1 piping systems use a certain conservative factor.

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 113 clarification on whether the applicants cycle projections use a certain conservative factor.

4 4.3.3 4-50 For the primary sampling system, SLRA Table 4.3.3-2 indicates that the number of 80-year cycles related to pressurizer steam and liquid space sampling is 5520 cycles.

The table also indicates that the number of 80-year cycles related to residual heat removal loop sampling is 2760 cycles. The table further indicates that the number of 80-year cycles related to reactor coolant system sampling is 920 cycles.

However, SLRA Table 4.3.2-2 does not clearly discuss whether each of these cycles is applied to a different piping line in the primary sampling system (meaning no need to add these cycles cumulatively for the primary sampling system analysis).

36. Clarify whether each of the 80-year cycles (i.e.,

5520, 2760 and 920 cycles) discussed in the issue section is applied to different piping lines in the primary sampling system respectively (meaning no need to add these cycles cumulatively for the primary sampling system analysis).

Environmentally Assisted Fatigue (EAF)

Question Number SLRA Section SLRA Page Background / Issue Discussion Question / Request 1

Section, 4.3.4 Table 4.3.4-1 4-59, 4-60 SLRA Section 4.3.4 addresses the EAF TLAA.

Specifically, SLRA Table 4.3.4-1 describes the limiting EAF locations (also called sentinel locations). SLRA Table 4.3.4-1 indicates that in terms of EAF, the reactor vessel vent pipe (fabricated with nickel alloy) is bounded by the

37. Clarify whether the reactor vessel vent pipe and steam generator tubes are in the same transient section (also called thermal zone). If so, explain the technical basis of the applicants determination (i.e., the two components are in the same transient section). If not, explain how

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 114 steam generator tubes (fabricated with nickel alloy).

However, it is not clear to the staff whether the reactor vessel vent pipe and steam generator tubes are in the same transient section (also called thermal zone) that experiences essentially the same pressure and temperature transients such that the bounding nature of the steam generator tubes for the vent pipe can be determined.

the applicant determined that the vent pipe is bounded by the steam generator tubes in terms of EAF even though these two components are not in the same transient section.

2. Clarify whether the vent pipe discussed is the pipe connected to the vent penetration of the reactor vessel closure head. In addition, discuss the applicants inspections on the vent pipe and their results as part of OE evaluation to confirm that there is no relevant indication that can affect the integrity of the vent pipe.

2 4.3.4 4-54 SLRA Section 4.3.4 discusses the screening evaluation for EAF to determine the plant-specific limiting locations (also called sentinel locations) for the ASME Code Section III vessels and pressurizer surge line, which may be more limiting than the NUREG/CR-6260 locations.

SLRA Section 4.3.4 explains that the calculations of the screening CUFen valves for the ASME Code Section III vessels and pressurizer surge line use the maximum Fen values in accordance with NUREG/CR-6909, Revision 1.

The staff needs clarification on how the applicant estimated the maximum Fen (environmental fatigue correction factor) values for each material type in the screening evaluation for EAF.

SLRA Section 4.3.4 also indicates that some of the limiting EAF locations for the ASME Code Section III vessels and pressurizer surge line needed more detailed CUFen (environmentally adjusted CUF) calculations to remove excessive conservatisms

3. With respect to the EAF screening evaluation for the ASME Code Section III vessels and pressurizer surge line, clarify how the applicant estimated the maximum Fen As part of the discussion, clarify how the applicant determined the temperature, strain rate and sulfur content (for carbon and low alloy steels) in the Fen calculations for the EAF screening.
4. If the screening Fen calculations use the maximum temperature specified in NUREG/CR-6909, Revision 1 as part of the evaluation, clarify whether the maximum temperature of each related transient exceeds the maximum temperature specified in NUREG/CR-6909, Revision 1. If so, describe the maximum and minimum temperatures for each of the transients, which have the maximum temperature exceeding the maximum temperature specified in the NUREG report, to confirm that the use of the maximum temperature specified in NUREG report, is reasonable or conservative compared to the

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 115 associated with the screening CUFen values after the EAF screening evaluation. The staff needs clarification on how the applicant refined the screening CUFen values to remove the excessive conservatisms in the detailed evaluation.

In addition, the staff needs clarification on the specific vessels included in the EAF analysis (i.e.,

screening and detailed evaluations for EAF).

transient temperature range.

5. Discuss how the applicant removed the excessive conservatisms associated with the screening CUFen values in the detailed evaluation after the EAF screening evaluation.
6. Clarify the specific vessels included in the EAF analysis.

3 4.3.4 4-55 SLRA Section 4.3.4 discusses the screening evaluation to determine the plant-specific limiting locations for the reactor coolant pressure boundary piping designed per ANSI B31.1 code, which may be more limiting than the NUREG/CR-6260 locations.

SLRA Section 4.3.4 does not clearly discuss how the applicant determined the screening Fen values for the ANSI B31.1 piping.

In addition, SLRA Section 4.3.4 does not clearly discuss whether some of the limiting EAF locations for the piping designed per ANSI B31.1 code needed more detailed CUFen calculations to remove excessive conservatisms associated with the screening CUFen values after the EAF screening evaluation. If so, the staff needs clarification on how the applicant refined the screening CUFen values to remove the excessive conservatisms in the detailed evaluation.

7. Describe the reactor coolant pressure boundary piping lines designed per ANSI B31.1 code that are evaluated in the EAF analysis.
8. With respect to the EAF screening evaluation for the piping designed per ANSI B31.1, clarify how the applicant estimated the conservative Fen As part of the discussion, clarify how the applicant determined the temperature, strain rate and sulfur content (for carbon and low alloy steels) in the Fen calculations for the screening.
9. If the screening Fen calculations use the maximum temperature specified in NUREG/CR-6909, Revision 1 as part of evaluation, clarify whether the maximum temperature of each related transient exceeds the maximum temperature specified in NUREG/CR-6909, Revision 1. If so, describe the maximum and minimum temperatures of each of the transients, which have the maximum temperature exceeding the maximum temperature specified in the NUREG report, to confirm that the use of the maximum temperature in NUREG report is reasonable or conservative compared to the transient temperature range.

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 116

10. Discuss how the applicant removed the excessive conservatisms associated with the screening CUFen values in the detailed evaluation after the EAF screening evaluation, as applicable.

4 4.3.4 4-52, 4-55 SLRA Section 4.3.4 indicates that the applicant performed detailed EAF evaluations to reduce the excessive conservatisms associated with screening Fen calculations after the EAF screening evaluation for (1) ASME Code Section III vessels and pressurizer surge line and (2) reactor coolant pressure boundary piping designed per ANSI B31.1 code.

In comparison, NUREG/CR-6909, Rev. 1, Section 4.1.4 indicates that the average temperature approach for Fen calculation (i.e., Fen calculation with the average temperature of a transient) can be used for a simple, linear transient with the threshold temperature for EAF. A conservative approach than the average temperature approach is the Fen calculation with the maximum temperature of each transient.

SLRA Section 4.3.3 does not clearly discuss the following: (1) whether the average temperature approach is used for the Fen calculation in the detailed evaluation after the screening evaluation; and (2) if so, the average temperature approach is used only for a simple, linear transient; and (3) if the average temperature approach is used for a complex transient, why the conservatism of the applicants approach is comparable to or greater than that of the modified rate approach described

11. For (a) ASME Code Section III vessels and pressurizer surge line and (b) reactor coolant pressure boundary piping designed per ANSI B31.1 code, respectively, clarify the following:

(1) whether the average temperature approach is used for the Fen calculation in the detailed EAF evaluation after the screening evaluation; and (2) if so, whether the average temperature approach is used only for a simple, linear transient and whether the Fen threshold temperature for each material type is used per NUREG/CR-6909, Revision 1 (e.g., 150 °C for carbon and low alloy steels).

12. For (a) ASME Code Section III vessels and pressurizer surge line and (b) reactor coolant pressure boundary piping designed per ANSI B31.1 code, respectively, if the average temperature approach is used for complex transients in the detailed EAF evaluation, describe the following: (1) what are the complex transients; (2) what are the components for which the complex transients are evaluated; and (3) why the conservatism of the applicants average temperature approach is comparable to or greater than that of the modified rate approach described in NUREG/CR-6909, Rev.

1, Section 4.4 (i.e., plant-specific demonstration of the adequacy of the applicants approach by

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 117 in NUREG/CR-6909, Rev. 1, Section 4.4 (i.e.,

plant-specific demonstration of the adequacy of the applicants approach).

comparing the Fen and CUFen values between the average temperature approach and the modified rate approach).

5 4.3.4 4-56 SLRA Section 4.3.4 addresses the flaw tolerance analysis for the reactor vessel outlet nozzle-to-shell weld in accordance with ASME Code Section XI, Appendix A.

The staff noted that the flaw tolerance analysis is based on the flaw tolerance analysis for the reactor vessel shell-to-inlet nozzle welds that are described in PWR owner's group (PWROG)-

17031-NP-A, Revision 1, Update for Subsequent License Renewal: WCAP-15338-A, A Review of Cracking Associated with Weld Deposited Cladding in Operating PWR Plants. (ADAMS Accession No. ML20132A221).

However, SLRA Section 4.3.4 does not clearly discuss the technical basis for the applicants determination that the flaw tolerance evaluation for the reactor vessel inlet nozzles in the PWROG report is bounding for or representing the applicants reactor vessel outlet nozzles.

13. Describe the technical basis of the applicants determination that the flaw tolerance analysis for the reactor vessel inlet nozzles in PWROG-17031-NP-A, Revision 1 is bounding for or representing the applicants reactor vessel outlet nozzles in terms of fatigue crack growth and allowable flaw size.
14. In addition, discuss the periodic inspections that are performed on the reactor vessel outlet nozzle-to-shell weld and the inspection results to confirm the absence of relevant indications in the weld.

6 4.3.4, B3.1 4-56, B-258 The OE section in SLRA Section B3.1 for the Fatigue Monitoring AMP indicates that for SLR, thermal stratification of the pressurizer spray line and the effects of fatigue and EAF were evaluated.

The OE section also explains that this location has been included in the Fatigue Monitoring AMP and has been dispositioned with an ASME Code Section XI Appendix L flaw tolerance evaluation.

15. Resolve the potential inconsistency between SLRA Section B3.1 and SLRA Section 4.3.4 in terms of the use of the provisions in ASME Code Section XI Appendix L to manage the aging effect of EAF in the pressurizer spray line.
16. Clarify the following items related to the Appendix L flaw tolerance analysis for pressurizer spray line: (1) maximum allowable

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 118 In contrast, the pressurizer spray line is not discussed in SLRA Section 4.3.4 that addresses EAF analysis and the related Appendix L flaw tolerance analysis. In addition, SLRA Table 4.3.4-1 does not identify the pressurizer spray line as a component location that managed by using the Appendix L flaw tolerance analysis.

crack growth period determined in flaw tolerance analysis; (2) specific limiting location of the pressurizer spray line; and (3) inspection frequency to be used in the fatigue management.

7 4.3.4, B3.1 4-56, B-258 SLRA Section 4.3.4 and Section B3.1 indicate that Appendix L flaw tolerance analyses were performed on the following components to manage the effect of EAF for 80 years of operation: (1) pressurizer surge reducer-to-pipe weld; (2) charging nozzle-to-pipe weld; and (3) pressurizer spray line.

SLRA Section 4.3.4 also explains that the flaw tolerance analyses use the fatigue crack growth rates described in ASME Code,Section XI, Code Case N-809.

The staff noted that in Code Case N-809, the parameter defining the effect of metal temperature on fatigue crack growth rate (ST) has a minimum value at 300 °F for austenitic stainless steels.

Therefore, how the metal temperature is defined in the calculations of ST values may result in non-conservative fatigue crack growth rates. The staff needs clarification on whether the applicant determined the ST values for the fatigue transients in such a manner to estimate conservatively bounding ST values.

17. With respect to the Appendix L analyses for the components listed in the issue section, describe how the applicant determined the metal temperature in the calculation of the ST value for each fatigue crack growth transient. As part of the discussion, clarify whether the applicant determined the metal temperature in such a manner to estimate conservatively bounding ST value for each transient.
18. If the maximum metal temperature is used in the calculation of the ST value for each transient, provide the following information: (1) whether the ST value at the maximum metal temperature for the transient is comparable to or bounding for that at the minimum metal temperature; and (2) the maximum metal temperatures used in the ST calculations are equal to or greater than 500 °F such that the ST values based on the maximum metal temperature are comparable to or greater than the ST value at 70 °F that reasonably represents the room temperature (i.e., the lowest possible minimum temperature).

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 119 (Site-Specific) Reactor Coolant Pump Flywheel Analyses Question Number SLRA Section SLRA Page Background / Issue Discussion Question / Request 1

4.7.2 4-74 to 4-76 The applicant did not discuss whether any indication(s)/flaw(s) were detected in the RCP flywheel. This information is needed to evaluate the postulated flaw used in the topical report PWROG-17011-NP-A.

a. Discuss whether any indications/flaws were detected in the RCP flywheel.
b. If indications/flaws were detected, (1) provide the document that identifies the indications/flaws and associated history. Alternatively, discuss the flaw size (length and depth),

the location of the flaw in the flywheel, the year of the detection, and the disposition of the flaw(s). (2) Identify any flaw(s) that still remain in service. (3) Discuss whether the detected flaw size is bound by the postulated flaw size in the flaw evaluation as shown in PWROG-17011-NP-A.

(Site-Specific) Leak-Before-Break of Reactor Coolant System Loop Piping Question Number SLRA Section SLRA Page Background / Issue Discussion Question / Request 1

4.7.3.1 4.77 In Section 4.7.3.1 (LEAK-BEFORE-BREAK OF REACTOR COOLANT SYSTEM LOOP PIPING), the TLAA evaluation on page 4.77 states that alloy 82/182 welds are present at the reactor pressure vessel nozzle (RPVON) and reactor pressure vessel inlet nozzle (RPVIN) and they are susceptible to PWSCC (Primary Water Stress Corrosion Cracking). However, there is very little discussion as to the measures that are being implemented for PWSCC concerns.

In WCAP-15628-P, Revision 1, "Technical Justification for Eliminating Large Primary Loop Pipe Rupture as the Structural Design Basis for H.B.

Robinson Unit 2 Nuclear Power Plant for the Subsequent License Renewal Program," May 2024, Section 2.1 Stress Corrosion Cracking, discusses the inspections that are being performed on the hot and cold legs of the RPVON and RPVIN using ASME Code Case N-770-5. Additionally, the zinc injection program is discussed which provides some

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 120 mitigation with respect to slowing the initiation and propagation of PWSCC. This discussion should be added to the SLRA as this information will be helpful in enhancing the quality of the Safety Evaluation.

2 4.7.3.1 4-77 In the TLAA evaluation item (d) states that water hammer should not occur in the reactor coolant system (RCS) piping because of system design, testing, and operational considerations. In WCAP-15628 Rev. 1 there is a discussion about why the potential is low in the RCS for water hammer along with OE.

The discussion needs to be expanded to include additional information provided in WCAP-15628 Rev.1 in the SLRA. The additional information provided in the SLRA will enhance the quality of the final safety evaluation.

3 4.7.3.1 4-77 In the TLAA evaluation on page 4-77, it states that the effects of low and high cycle fatigue on the integrity of the primary piping are negligible. Is this statement based on using stress reduction factors for ASME BPV Code Section III? The ASME Code Section III defines stress intensification factors for various piping components under fatigue loading. The statement in the SLRA does not provide any supporting statement as to why the effects of low and high cycle fatigue are negligible on the primary piping.

In WCAP-15628 Rev.1, Section 2.3 provides the additional information that should be added to the SLRA which supports the statement as to why the effects of low and high cycle fatigue are negligible in the primary piping systems. Provide additional information in the SLRA to support the statement for low and high cycle fatigue. This additional information will strengthen the final safety evaluation.

(Site-Specific) Reactor Vessel Underclad Cracking Question Number SLRA Section SLRA Page Background / Issue Discussion Question / Request 1

4.7.5 4-80 SLRA Section 4.7.5 does not discuss whether any indication(s) / flaw(s) were detected in the reactor vessel underclad. This information is needed to

a. Discuss whether any indications/flaws were detected in the reactor vessel underclad.
b. If indications/flaws were detected, (1) provide the

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 121 evaluate the postulated flaw used in the topical report PWROG-17031-NP-A.

document that identifies the indications/flaws and associated history. Alternatively, discuss the flaw size (length and depth), the location of the flaw in the flywheel, the year of the detection, and the disposition of the flaw(s). (2) Identify any flaw(s) that remain in service. (3) Discuss whether the detected flaw size is bound by the postulated flaw size in the flaw evaluation as shown in PWROG-17031-NP-A.

2 4.7.5 4-81 Under the heading TLAA Action Item 1, the applicant cited reference 4.7.5-5. The staff cannot find reference 4.7.5-5 in the SLRA.

Provide in the e-Portal reference 4.7.5-5.

3 TLAA Action Item 2 states that To ensure the continued validity of 200 ksi in toughness for RPV beltline forgings, based on an adjusted RTNDT less than or equal to 270°F for the high fluid temperature transients, SLR applicants are to confirm that their limiting SA-508, Class 2 or Class 3 RPV beltline forgings meet the PTS [pressurized thermal shock]

screening criterion of 270°F in 10 CFR 50.61 In response to TLAA Action Item 2, the applicant stated that the reactor vessel lower, intermediate, and upper shells are all made from A302B plate material and are not susceptible to underclad (reheat) cracking.

Based on the staffs understanding, A302B can be susceptible to underclad cracking. A302B is a manganese-molybdenum steel. Steels with molybdenum are more susceptible to reheat cracking due to their hardenability and potential for forming Provide additional details and discussion as to why A302B plate material is not susceptible to underclad (reheat) cracking.

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 122 brittle microstructures during post-weld heat treatment. The presence of residual elements such as sulfur, phosphorus and tramp elements can also increase susceptibility.

(Site-Specific) Prestressed Concrete Containment with Grouted Tendons Question Number SLRA Section SLRA Page Background / Issue Discussion Question / Request 1

SLRA A4.7.7 A-45 The third paragraph of SLRA Section A4.7.7 states in part, testing (at ILRT pressure), similar to the Structural Integrity Test (SIT) performed in 1992, will be scheduled to coincide with Appendix J.

It is unclear if the Structural Integrity Test performed in 2020 should also be reference assuming the latest procedure may be more updated.

It was stated in the license renewal application (LRA), Robinson committed to perform SIT of the containment two times during period of extended operation (PEO). It is unclear what year(s) the next SIT will be performed during the SPEO.

19. Evaluate whether reference to the 2020 SIT should be included in the 3rd paragraph
20. Provide the anticipated years that the SIT of the containment building will be performed during the SPEO.

2 SLRA A4.7.7; 25-Year Tendon Prestress surveillance 4-86; Pg 20 Subsection Surveillance tendon tests and results, states, Robinson had two surveillance tendons, each consisting of two short tendons, similar to the service tendons, and were in a

1. Confirm the size of the surveillance tendons described in the SLRA and update as appropriate.

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 123 block similar environment. Each tendon consists of six-1.375-inch diameter bars in a 6 inch diameter pipe sheath...

Table 2, Tendon Bar Tensile Test Mechanical Properties Results, of the 25-year surveillance report indicates that the tested tendon bars are 0.5.

It appears theres a discrepancy in the SLRA and the 25-year surveillance report on the size of the surveillance tendons.

3 SLRA 4.7.7 4-87 Subsection Surveillance tendon tests and results, Bullet 5 of the 5-year surveillance tendon inspections described a 40% low reduction in area on Bar 6, and further stated it coincide with the existence of a flaw on the fracture surface.

It is unclear what 40% low reduction in area and coincides with an existing flaw on the fracture surface means.

21. Provide explanation what 40% low reduction in area means/
22. Explain what flaw on the fracture surface means? Is the flaw originated from fabrication of the bar?

4 SLR-RNP-TLAA-0707, Pg 2/3 The Assumptions for long term loss pattern calculations: 65% tendon PS loss by year 1, 30% tendon PS loss between 1 to 50 years, 5%

tendon PS loss between 50-60 years, and 4%

tendon PS loss between 60-80 years.

It is unclear what research document this data comes from. The wording of the four bullets for each Tendon Prestress Loss, indicates the loss of PS is by the percentage for each time frame instead of a percentage of the total loss

23. Provide reference documents to support how the tendon PS losses were estimated for each of the time frames.
24. Clarify the wording in the four bullets whether it should be % tendon PS loss or

% of total tendon PS loss

25. Explain why the total % of all four bullets exceed 100%.

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 124 for each time frame. And the sum of the % PS losses for the four bullets add up to more than 100% (104).

5 SLR-RNP-TLAA-0707, ;

RNP-C/CONT-1004, Rev 2 Pg 2-3; Pg 22, 34 The TLAA 0707 document evaluates the prestress loss between 60 to 80 years to be 1.819 ksi. The total area of PS tendons is 8.91in2, which results in a PT force loss of 1.819ksi*8.91= 16.2 kip. On Table 3 (page 34) of the CONT-1004 calculation, the net loss for the tendons between 60 and 80 years is approximately interpolated to be 5kip; which is drastically different from the estimated loss of 16.2 kip.

Additionally, on page 3 of the Attachment 1 for TLAA-0707 document, the independent losses were reported to be 27.49 psi, whereas the calculated net tendon stress losses at 100 years on page 22 of CONT-1004 were 19.68 ksi, representing a big disparity between the two values.

It is unclear why estimated PS losses in the TLAA 0707 document are so different from the CONT-1004 calculation.

Verify the accuracy of the estimated PS tendon losses for each of the time periods and/or verify the accuracy of the CONT-1004 calculation and confirm that the estimated losses used in the TLAA-0707 document are accurate to estimate the projected PS tendon stress loss to the end of the SPEO.

6 SLR-RNP-TLAA-0707, ;

RNP-C/CONT-1004, Rev 2 Pg 2; Pg 22 UFSAR page 3.8.1-8, first paragraph, describes the grip nut is a modified positive action wedge anchor.

Section 2.3 of TLAA 0707, Attachment 1, summarizes the net loss of tendon stress as summation of losses due to tendon relaxation, concrete shrinkage, and concrete creep. The

26. Confirm that the initial tendon prestress force accounts for losses due to anchor set during the transfer of tensioning from the jack to the modified wedge anchors. Or provide documentation to show that anchor set losses are not applicable to the prestress anchorage design.

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 125 net loss of prestress does not include losses due to anchorage set or seating loss.

It is unclear if anchor set loss was considered in calculating the prestressing force transferred to the bearing plate after the release of the jacks.

If anchor set force losses are applicable, then the actual initial prestress force on the bearing plates would not be 120ksi.

27. Provide update to the available tendon prestress if anchor set losses should be counted and make appropriate updates to the SLRA Section 4.7.7.

(Site-Specific) Concrete Containment Bonded Tendon Prestress Question Number SLRA Section SLRA Page Background / Issue Discussion Question / Request 1

SLRA B4.1 B - 271 SLR-SRP A.1.2.3.5 states in part, monitoring and trending activities should be described, and they should provide a prediction of the extent of degradation...Results of inspections in the prior period... are used to provide input to the trending results.

Element 5 of SLRA AMP B4.1 describes the acceptance criteria values are compared to the values measured during the previous SIT that were performed in 1970, 1992, and 2020.

It is unclear whether trending of the SIT was performed and evaluated to predict the performance of the containment up to the end of SPEO.

Monitoring and Trending:

Provide a description if monitoring and trending activities were performed when evaluating the SIT results, and describe if the trend will remain above the acceptance limits through the end of SPEO.

2 SLRA B4.1; SP-1068; RNP-B - 271; Pg 10 of Element 6 of SLRA AMP B4.1 describes the displacements obtained are compared against the Acceptance Criteria:

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 126 C/STRU-1416, Attachment B 126; B3-B6 acceptance criteria identified in station procedures and the displacements measured during the previous SITs that were performed in 1970, 1992, and 2020 Section 5.0, Acceptance Criteria, of the SP-1068 document provides the various acceptance values for elongation and cracking of the containment under tests pressure, which was derived and scaled from Ebasco Services Inc. The acceptance criteria values are greater than the calculated values used in Attachment B of RNP-C/STRU-1416, SIT Unexpected Response Contingency Plan.

It is unclear what is the correlation between the Acceptance criteria limits and the design and performance of the Containment building.

a. Explain how the acceptance criteria limits for basemat vertical displacement, containment wall elongation, crack width, and crack spacing were determined relative to the design limits for the containment building
b. Explain the margins or the safety factors, if any, in determining the acceptance criteria for the containment SIT testing.

3 SLRA B4.1; RNP-C-STRU-

1416, Attachment B B-271; B6-B8 Element 7 of SLRA describes that site documents that implement the AMPs for LR direct that an NCR be prepared whenever non-conforming conditions are found (i.e., the acceptance criteria are not met).

The technical specifications (TS) do not provide acceptance limits for the containment tendon testing, which may include reporting requirements.

Attachment B of RNP-C-1416, Section 3, contingency actions, describes actions to be taken when indications of potential loss of vertical prestressing are observed during the containment pressurization. The contingency actions include a full structural review and assessment of the acceptance criteria by the RE but does not include Corrective Actions:

Clarify whether the description in Element 7 of the AMP is consistent with the requirements in the TS and the contingency actions described in Attachment B to RNP-C/STRU-1416.

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 127 any reporting actions.

It is unclear whether the whether the testing of the containment SIT has NCR reporting requirements because acceptance limits are not provided in the tech specs, and Attachment B to RNC-C-1416 does not describe reporting actions.

4 SLRA B4.1; 4.7.7 B-273; 4-87; Element 10, item 1, describes, in 2010, a corrective action was created to generate a new model WO for performing the SIT as part of the license renewal commitment implementation work to coincide with 10CFR Appendix J ILRT.

SLRA Section 4.7.7 states, as part of the initial license renewal SER, RNB committed to perform SIT of the containment building two times during the PEO. Table 4.7.7-2 provides summaries of the SIT for 1970, 1974, 1992, and 2020 (a 28-year gap between the last two SITs)

In response to the request for additional information (RAI) questions, (ML031210148) during initial license renewal, response to RAI 4.5-2 mentions that the SIT will be scheduled to coincide with Appendix J ILRT. It is unclear when the license amendment request (LAR) was requested to perform the Containment SIT coincidently with the 10CFR Appendix J program, and what the proposed schedules for the testing are for the PEO.

On NRCs SE of RNPs LAR for extension of the Appendix J ILRT frequency in 2016 (ML16201A195),

it was noted that a containment ILRT type A test was performed in May of 2007. It is unclear why a SIT Operating Experience

a. Provide documentation that explains when the proposal to perform the containment SIT concurrently with the Appendix J ILRT was approved and provide the proposed schedules for Appendix J and SIT testing after 1992.
b. Explain why a containment SIT was not performed in 2007 with the Appendix J ILRT resulting in a 28-year gap between the 1992 SIT and 2020 SIT with no containment structural testing performed.
c. Explain what the schedule is to fulfilling the LRA commitment of performing two containment SITs during the PEO.

H.B. Robinson 2, Unit 2 Subsequent License Renewal Application (SLRA) Breakout Audit Questions 128 was not performed during the same time in 2007 if the SIT is following the Appendix Js ILRT intervals.

Additionally, it appears only one of the two LRA commitments have been performed for the PEO (2010-2030).

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