ML11250A043

Requests for Additional Information for the Review of the South Texas Project, Units 1 and 2 License Renewal Application - Aging Management Review, Set 1

ML11250A043
Person / Time
Site:	South Texas
Issue date:	09/22/2011
From:	Daily J License Renewal Projects Branch 1
To:	Gerry Powell South Texas
Daily J
References
TAC ME4936, TAC ME4937
Download: ML11250A043 (65)

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,,0 Mr. G. T. Powell, Vice President Technical Support and Oversight STP Nuclear Operating Company P.O. Box 289 Wadsworth, TX 77483

SUBJECT:

REQUESTS FOR ADDITIONAL INFORMATION FOR THE REVIEW OF THE SOUTH TEXAS PROJECT, UNITS 1 AND 2 LICENSE RENEWAL APPLICATION - AGING MANAGEMENT REVIEW, SET 1 (T AC NOS. ME4936 AND ME4937)

Dear Mr. Powell:

By letter dated October 25,2010, STP Nuclear Operating Company, submitted an application pursuant to Title 10 of the Code of Federal Regulations Part 54 for review by the U.S. Nuclear Regulatory Commission (NRC or the staff), to renew operating licenses NPF-76 and NPF-80 for South Texas Project, Units 1 and 2. The staff is reviewing the information contained in the license renewal application and has identified, in the two enclosures, areas where additional information is needed to complete the review.

These requests for additional information were discussed with Arden Aldridge, and mutually agreeable dates for the responses are by October 12, 2011, for Enclosure 1, and October 17, 2011, for Enclosure 2. If you have any questions, please contact me at 301-415-3873 or by e-mail at john.daily@nrc.gov.

Docket Nos. 50-498 and 50-499

Enclosures:

As stated cc w/encl: Listserv Sincerely,

~C)L~)~.'L John W. Daily, seni::::;c: Janager License Renewal Branch RPB1 Division of License Renewal Office of Nuclear Reactor Regulation

SOUTH TEXAS PROJECT, UNITS 1 AND 2 REQUEST FOR ADDITIONAL INFORMATION AGING MANAGEMENT REVIEW, SET 1 (TAC NOS. ME4936 AND ME4937)

Water Chemistry (002) and Internal Surfaces (039)

RAI3.3.2.3.19-1

Background:

In license renewal application (LRA) Table 3.3.2-19, the applicant states that a Chemical and Volume Control System stainless steel pump and valve exposed to zinc acetate will be managed for loss of material by the Water Chemistry program. LRA Table 3.3.2-19 also states that a thermoplastic tank exposed to zinc acetate will be managed for cracking by the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program.

NUREG-1801, "Generic Aging Lessons Learned (GALL) Report," does not specifically address the aging of stainless steel pumps, valves, or thermoplastics in a zinc acetate environment or identify associated aging effects.

Issue:

The aging of stainless steel and thermoplastic materials can be exacerbated under certain operating conditions and in the presence of certain impurities in the process stream. In order for the staff to evaluate whether the proposed aging management programs adequately manage the effects of aging for materials exposed to zinc acetate, additional information is needed regarding component/system operating parameters (Le., zinc acetate concentration, design temperature and normal operating temperature) as well as information regarding the possible existence of impurities (e.g., oxygen, chlorides, fluorides, sulfates).

Reguest:

For each component subject to a loss of material and cracking aging effect in a zinc acetate environment, state the system's design temperature, minimum and maximum operating temperature, the normal operating temperature at which the component is exposed and the concentration of the zinc acetate. Also, provide all concentration limits that are specified for impurities in the system, including, but not limited to, oxygen, chlorides, fluorides, sulfates, etc.

ENCLOSURE 1

- 2 RAJ 3.3.2.3.22-1

Background:

The LRA discusses the need to manage the aging of a variety of materials exposed to sodium hydroxide. For example:

LRA Table 3.3.2-22, states that the stainless steel piping exposed to sodium hydroxide, in the Liquid Waste Processing System, will be managed for loss of material by the Water Chemistry program.

LRA Table 3.3.2-27, states that the stainless steel accumulator, piping, pump, sight gauge, strainer, tank and valve exposed to sodium hydroxide, in the miscellaneous systems in scope only for criterion 10 CFR 54.4(a)(2), will be managed for loss of material by the Water Chemistry program and that the nickel alloy piping and valve exposed to sodium hydroxide will be managed for loss of material by the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program.

• LRA Table 3.3.2-27 states that a glass sight gauge exposed to sodium hydroxide will be managed for loss of material by the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program.

The GALL Report does not specifically address the aging of glass, stainless steel, or nickel alloy piping and piping components in a sodium hydroxide environment or identify associated aging effects.

Issue:

The aging of stainless steel and glass can be exacerbated under certain operating conditions and in the presence of certain impurities in the process stream. In order for the staff to evaluate whether the proposed aging management programs adequately manage the effects of aging for materials exposed to sodium hydroxide, additional information is needed regarding component/system operating parameters (Le., sodium hydroxide concentration, design temperature and normal operating temperature) as well as information regarding the possible existence of impurities (e.g., oxygen, chlorides, fluorides, sulfates).

Request:

The applicant is requested to identify, for each component subject to a loss of material aging effect in a sodium hydroxide environment, the system's design temperature, minimum and maximum operating temperature, the normal operating temperature at which the component is exposed and the concentration, of the sodium hydroxide. Also, provide all concentration limits that are specified for impurities in the system, including, but not limited to, oxygen, chlorides, fluorides, sulfates, etc.

- 3 Thermal Aging Embrittlement (013)

RAJ 3.1.1.57-1

Background:

LRA Section B2 states that the GALL Report aging management program (AMP) XI.M12, "Thermal Aging Embrittlement of Cast Austenitic Stainless Steel Program (CASS)," is not credited. LRA Table 3.1.1, item 3.1.1.57 states that portions of the reactor coolant loops are constructed of CASS and that the straight piping pieces are centrifugally cast and that the fittings are statically cast. In addition, the applicant stated that the molybdenum and ferrite values for these fittings and piping pieces are below the industry accepted thermal aging significance threshold; therefore, thermal aging of CASS reactor coolant piping is not a concern.

GALL AMP XI.M12, states that for low-molybdenum content steels (SA-351 Grades CF3, CF3A, CF8, CF8A or other steels with s 0.5 wt. % Mo), only static-cast steels with >20% ferrite are potentially susceptible to thermal embrittlement. In addition, for high-molybdenum content steels (SA-351 Grades CF3M, CF3MA, and CF8M or other steels with 2.0 to 3.0 wt.% Mo),

static-cast steels with >14% ferrite are potentially susceptible to thermal embrittlement.

Updated Final Safety Analysis Report (UFSAR) Table 5.2-2 indicates that the reactor coolant pipe is made of centrifugally-cast SA-351, Grade CF8A and that the reactor coolant fittings are made of SA-351, Grade CR8A. South Texas Project (STP) UFSAR Table 5.2-1 indicates that the 1974 edition through winter 1975 of American Society of Mechanical Engineers Boiler and Pressure Vessel Code (ASME Code),Section III is applicable for the construction of the reactor coolant pipe. The staff noted that the centrifugally-cast SA-351, Grade CF8A is not susceptible to thermal aging embrittlement in accordance with the guidance in the GALL Report.

Issue:

For the reactor coolant fittings, neither the GALL Report nor the 1974 edition of ASME Code Section II, Part A, Specification SA-351 identifies "Grade CR8A n as a material grade for fabrication of Code Class CASS components. Therefore, the staff needs additional information regarding the SA-351 material grade that was used to fabricate the static-cast reactor coolant fittings, and the molybdenum and ferrite contents for this material, to determine the material's susceptibility to thermal aging embrittlement.

Request:

• Clarify whether the reference in UFSAR Table 5.2-2 to SA-351, CR8A is accurate and refers to an actual material.

If the reference to SA-351, CR8A in UFSAR Table 5.2-2 is correct, provide the information on the molybdenum and ferrite contents of the static-cast SA-351 "Grade CR8A n material. In addition, justify why this static-cast stainless steel is not susceptible to loss of fracture toughness due to thermal aging embrittlement. If the material is susceptible to loss of fracture toughness, propose an aging management program to adequately manage this aging effect.

- 4 If the reference to SA-351, CR8A in UFSAR Table 5.2-2 is not correct, identify the correct material grade in SA-351 that represents the actual material for the fittings and provide the information on the molybdenum and ferrite contents of this material. In addition, justify why this material is not susceptible to loss of fracture toughness due to thermal aging embrittlement. If the material is susceptible to loss of facture toughness, propose an aging management program to adequately manage this aging effect.

Flow-Accelerated Corrosion (018)

RAI 3.4.2.6-1

Background:

The LRA states that the Flow Accelerated Corrosion (FAC) Program implements the Electric Power Research Institute (EPRI) guidelines in NSAC-202L-R3 to detect, measure, monitor, predict, and mitigate component wall thinning. The guidance in NSAC-202L states that systems with low operating times may be excluded from further evaluation. However, NSAC-202L also cautions that some lines that operate less than 2 percent of the time have experienced damage caused by FAC and that these lines should be excluded only if no wear has been observed.

Issue:

South Texas Project Condition Records CR 05-6563 and CR 07-5543 indicate that wall thinning due to FAC was identified within components of the auxiliary feedwater system. However, the aging management review results in Table 3.4.2-6 for the auxiliary feedwater system do not include piping components being managed by the FAC Program.

Reguest:

Provide technical information that supports the omission of piping and piping components in the auxiliary feedwater system from coverage by the FAC Program.

If it is determined that the FAC Program is an applicable AMP for the auxiliary feedwater system, then provide information regarding actions to ensure that plant-specific operating experience has been considered in all other systems where flow accelerated corrosion has been identified.

Bolting Integrity (019)

RAI 3.2.2.1-1

Background:

The GALL Report, Table IV.C2, recommends that stainless steel closure bolting in an environment of air with reactor coolant leakage be managed by the Bolting Integrity AMP for loss of preload and cracking aging effects. LRA Tables 3.2.2-1,3.2.2-4,3.3.2-8,3.3.2-19,

- 5 3.3.2-22, 3.3.2-23, and 3.3.2-27 state that stainless steel closure bolting with borated water leakage is managed by the Bolting Integrity AMP for the loss of preload aging effect only.

Issue:

It is not clear to the staff why the applicant does not consider cracking to be an aging effect of stainless steel closure bolting in an environment of air with borated water leakage.

Request:

Provide additional information showing why stainless steel closure bolting with borated water leakage does not need to be managed for the aging effect of cracking, or provide information showing that the aging effect of cracking is being managed for this component, material, and environment combination.

RAI 3.3.2.13-1 Backqround:

The GALL Report, Table VILI, recommends that carbon steel closure bolting in an air-indoor uncontrolled (external) environment should be managed by the Bolting Integrity AMP for loss of preload and loss of material aging effects. LRA Tables 3.3.2-13, and 3.3.2-15 state that carbon steel closure bolting with a plant indoor air environment is managed by the Bolting Integrity AMP for the loss of material aging effect. A plant-specific note 1 is added to the LRA table line items which states that, "Loss of preload is conservatively considered to be applicable for all closure bolting."

Issue:

Without specific LRA table line items that address the loss of preload associated with closure bolting, it is not clear to the staff that the plant-specific note 1, alone, provides a sufficient emphasis on the need to manage the loss of preload aging effect for carbon steel closure bolting with a plant indoor air environment under the Bolting Integrity program.

Request:

Provide a line item(s), as appropriate, indicating that the aging effect of loss of preload is being managed for this component, material, and environment combination or provide a justification for not including such line items.

RAt 3.5.2.11-1

Background:

The GALL Report, Table III.B1, recommends that high strength structural bolting made of low alloy steel in an air-indoor uncontrolled environment should be managed by the Bolting Integrity

-6 AMP for the cracking aging effect. Additionally, Table III.B1 recommends that structural bolting of any material in any environment should be managed for the loss of preload aging effect. LRA Table 3.5.2-11 states that high strength structural bolting made of low alloy steel in a plant indoor air environment is managed by the Bolting Integrity AMP for the cracking aging effect but does not address management of the loss of preload aging effect.

Issue:

It is not clear to the staff that the loss of preload aging effect is being managed for the high strength structural bolting components in table 3.5.2-11.

Request:

Provide a line item(s), as appropriate, indicating that the aging effect of loss of preload is being managed for this component, material, and environment combination or provide a justification for not including such line items.

Open-Cycle Cooling Water (021A)

RAI 8.2.1.9-2

Background:

During the system walkdown for the AMP Audit, the staff noted the presence of significant cavitation associated with the throttle valve downstream of the essential cooling water (ECW) return line for the component cooling water heat exchanger. Although not specifically discussed in the LRA, during its reviews of operating experience, the staff noted that this issue was documented in Licensee Event Report 499/2005004 (July 11, 2005) and was briefly discussed in the AMP basis document for the Open-Cycle Cooling Water Program. In addition, the AMP basis document discussed erosion-corrosion downstream of another throttle valve, as identified in CR 06-3132, which apparently resulted in the development of an "Erosion Monitoring Program," for the ECW system (see CR 07-14291). Also, as part of the AMP Audit, keyword searches of plant-specific corrective action documents identified additional condition records associated with the ECW system, with the search terms "erosion" and "cavitat," (e.g.,

CR 05-9516 and CR 06-16228), which appear to pertain to similar cavitation issues.

Issue:

Although LRA Section B2.1.9, "Open Cycle Cooling Water System," states that plant-specific operating experience identified erosion corrosion, no further details are discussed in the LRA.

The Open Cycle Cooling Water Program basis document uses the terms erosion and erosion-corrosion; but it was not clear to the staff to which aging mechanism(s) these terms applied, nor how loss of material due to the associated mechanism(s) will be managed in the period of extended operation. Since the identified cavitation erosion has apparently not been corrected, the applicant has chosen to manage the resulting loss of material caused by this erosion mechanism. It is the staff's view that GALL AMP XI.M20, "Open Cycle Cooling Water,"

- 7 only considers solid particle erosion; therefore, applicants that identify and choose to manage a different form of erosion should describe and explain this enhancement to the AMP.

Request:

1) Clarify how the Open-Cycle Cooling Water System Program manages the loss of material due to erosion corrosion resulting from the cavitation issues found in the Operating Experience review. If loss of material due to erosion corrosion is not being managed by this AMP, indicate which AMP will properly manage this aging effect and by what means it will be managed.

2) Provide details of the "Erosion Monitoring Program" for the ECW system that apparently resulted from plant operating experience in CR 06-3132 or similar CRs. Include a description of the methodology used to identify other locations in the ECW system for erosion monitoring.

3) Describe the extent of condition reviews performed to evaluate whether other systems' components within the scope of license renewal have comparable cavitation issues and discuss the results of these reviews.

RAI B.2.1.9-3

Background:

LRA Section B2.1.9 states that the program includes surveillance and control techniques to manage aging effects caused by protective coating failures in components of the ECW system.

The GALL Report defines one category of fouling as macrofouling due to peeled coatings and debris. During its review of operating experience, in CR 07-16847, the staff noted that the inspections of the diesel generator turbocharger intercooler found partial and full tube blockage with foreign material that was "consistent with erosion/corrosion of the coatings" used for the intercooler ribs. In addition, CR 10-12875 identified coating debris that caused blockage on the inside of the essential chiller endbell. Both condition records pertain to potential reduction of heat transfer due to fouling caused by protective coating failures.

Issue:

The LRA neither describes the protective coatings used in the ECW system nor discusses site-specific operating experience associated with protective coating failures to provide objective evidence supporting the conclusion that the effects of aging will be adequately managed during the period of extended operation.

Request:

Provide the bases showing that the surveillance and control techniques will adequately manage fouling of in-scope heat exchangers caused by protective coating failures. Include information to show that the size and amount of debris, which could potentially result from protective coating failures, will not affect intended functions of these downstream components.

- 8 RAI B.2.1.9-4

Background:

During its review of the program basis document for the open cycle cooling water system, the staff noted that coatings are applied to "mitigate cavitation and erosion damage" in the piping and valve body near the essential cooling water return throttle valves, and that these coatings are inspected during preventive maintenance activities approximately every 4 years. During its review of site-specific operating experience, in CR 07-8194, the staff noted that after approximately 2 years, the cavitation-resistant coatings were no longer present in the pipe and valve "cavitation impingement areas," and pipe metal wall loss was noted.

In addition, the AMP basis document states that, although the coatings protect the underlying metal surfaces from being exposed to the raw water environment, the coatings are not credited in aging management to protect metal surfaces.

Issue:

The staff questioned the adequacy of the approximately 4-year inspection frequency for the coatings cited in the AMP basis document. In addition, since the coatings were applied to mitigate cavitation damage, it was unclear that the coatings were not being credited to prevent loss of material in this program. For the coatings to not be credited for aging management, documentation should show that the components, without the protective coatings, will meet current licensing basis with the worst case loss of material which could occur between inspections.

Request:

1) Provide the technical bases that were used to justify the preventive maintenance inspection frequency of approximately 4 years, given that the cavitation-resistant coatings were apparently eroded away in less than 2 years. Include information demonstrating that the worst case operational parameters which affect cavitation severity and duration were considered.

2) Provide the technical bases to show that, without protective coatings, the loss of material due to worst case cavitation erosion will be adequately managed so that the intended function(s) will be maintained consistent with the current licensing basis.

Open-Cycle Cooling Water (021 B)

RAI 3.2.1.15-1

Background:

The GALL Report states that stainless steel containment isolation piping and components in the engineered safety features system exposed to raw water should be managed for loss of material due to general, pitting, crevice, and microbiologically influenced corrosion by the Open-Cycle Cooling Water System Program. The GALL Report states that these components

- 9 should also be managed for fouling that leads to corrosion by the Open-Cycle Cooling Water System Program. In the LRA items 3.2.1.15 and 3.2.1.35, the applicant has stated that the containment isolation piping and components in the engineered safety features system were evaluated in the systems in which the components were found to have the function of containment integrity.

Issue:

It was not clear to the staff where in the LRA the stainless steel containment isolation piping and components exposed to raw water are identified. In addition, it was not clear how the aging of containment isolation piping and components exposed to water will be managed.

Request:

Provide additional information for which systems the containment isolation piping and components were found to have the function of containment integrity. Provide additional information on what aging management program will be used to manage aging of these components exposed to raw water and provide technical information that supports the adequacy of this program.

RAI 3.3.1.76-1

Background:

The GALL Report states that steel (with coating or lining) piping, piping components, and piping elements exposed to raw water should be managed for loss of material due to general, pitting, crevice, and microbiologically influenced corrosion by the Open-Cycle Cooling Water System Program. The GALL Report states that these components should also be managed for fouling that leads to corrosion by the Open-Cycle Cooling Water System Program. The Open-Cycle Cooling Water System Program typically uses chemical treatment for biological fouling or flushing in addition to periodic inspections. LRA Table 3.3.2-27 states that carbon steel piping exposed to raw water being managed for loss of material will be managed by the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program.

Issue:

It is unclear to the staff how the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program, which only conducts visual inspection activities, is adequate to manage loss of material for the carbon steel piping exposed to raw water in the miscellaneous systems.

Request:

Justify using the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program to manage loss of material for the carbon steel piping exposed to raw water in the miscellaneous systems. Provide additional information on why chemical treatments or flushing is not required for these components.

- 10 RAI 3.3.2.6-1

Background:

Various types of titanium alloys exposed to raw water with chloride levels greater than several hundred ppm at high temperature can undergo loss of material due to crevice corrosion. The LRA Tables 3.3.2-6, 3.3.2-9, and 3.3.2-20 indicate that titanium heat exchangers are exposed to raw water and may be subject to reduction of heat transfer.

Issue:

It is not clear to the staff that the titanium alloy referenced in the LRA is resistant to crevice corrosion in the specific raw water environments addressed by the LRA AMP.

Reguest:

Provide additional information on what type of titanium alloys are used in the heat exchangers exposed to raw water and why aging management of loss of material due to crevice corrosion is not included.

One-Time Inspection (033)

RAI82.1.16-3

Background:

The GALL Report,Section XI.M32, "One-Time Inspection," "detection of aging effects" program element states that where practical, a representative sample size is 20% of the population or a maximum of 25 components for components managed by both the One-Time Inspection program and AMP XI.M2, "Water Chemistry;" AMP XI.M30, "Fuel Oil Chemistry;" and AMP XI.M39, "Lubricating Oil Analysis" programs. In lieu of using the recommended sample size, the GALL Report states that a technical justification of the sample size used for selecting components for one-time inspection should be included as part of the program's documentation.

LRA Section B.2.1.16, as amended on June 16, 2011, states the One-Time Inspection Program's sample size is based on groups sharing the same material, environment, and aging effects. The LRA also states that the components included in the sample size will be the most susceptible to degradation based on a review of environment, condition, and operating experience.

Issue:

The sample size stated in LRA Section B.2.1.16 is not consistent with the GALL Report recommendations and does not include a technical justification for this deviation from the GALL Report.

- 11 Request:

Revise LRA Section B.2.1.16 to reflect the GALL Report recommended representative sample size or provide a technical justification supporting the sample size currently stated in the LRA.

Metal Fatigue (060) 4.3-1

Background:

LRA Table 4.3-2 indicates the current cycle count for Transient 41 for Unit 1 (Charging Trip with Prompt Return to Service) is 10 as of the end of 2008.

Issue:

During its audit, the staff reviewed the applicant's design basis documents and noted that the current cycle count for Transient 41 for Unit 1 was 11 as of April 2005.

Request:

Justify the discrepancy; provide the correct current cycle count and the 60-year projected cycles for Transient 41 for Unit 1.

4.3-2

Background:

LRA Section 4.3.2.10 states that the TLAAs for Class 1 High Energy Line Break (HELB) locations are dispositioned in accordance with 10 CFR 54.21 (c)(1 )(iii), and that the effects of fatigue on the HELB locations will be managed by the Metal Fatigue of Reactor Coolant Pressure Boundary Program during the period of extended operation.

The staff noted that a CUF value less than 0.1 is one criterion for HELB location selection that is discussed in UFSAR Section 3.6.2.1.1. The staff also noted that, for the pressurizer surge line and accumulator safety injection lines, the applicant uses a criterion of 0.4 instead of 0.1 for the cumulative usage factor (CUF) value. In addition, a CUF value less than 1.0 is a cumulative fatigue damage design criteria in ASME Code Section III.

Issue:

The staff noted that it may be possible that the design cycle limit applicable to HELB piping locations can be less than the "UFSAR Design Cycles" and "Program Limiting Value" identified in LRA Table 4.3-2. In addition, the "acceptance criteria" program element in the Metal Fatigue of Reactor Coolant Pressure Boundary Program did not address how the acceptance criteria will be different for HELB and cumulative fatigue damage.

4.3-3

- 12 The Metal Fatigue of Reactor Coolant Pressure Boundary Program indicates that, when the accumulated cycles approach the design cycles, corrective actions will be taken to ensure the analyzed number of cycles is not exceeded; however, it is not clear to the staff if the applicant's program addresses the situation when the accumulated cycles approach the limit in the HELB analyses.

Reguest:

Identify the ASME Code Class 1 piping locations discussed in UFSAR Section 3.6.2.1.1 that are within the scope of LRA Section 4.3.2.10. For each location identified, provide the applicable design-basis transients and associated cycle limits.

Justify that the Metal Fatigue of Reactor Coolant Pressure Boundary Program can adequately ensure the CUF for HELB locations remain below 0.1 (or 0.4 for the pressurizer surge line and the accumulator safety injection line) by using systematic counting of plant transient cycles associated with the HELB analysis. Provide any appropriate revisions to the program elements of the Metal Fatigue of Reactor Coolant Pressure Boundary Program to incorporate activities for ensuring that the CUF for HELB locations remain below 0.1 (or 0.4 for the pressurizer surge line and the accumulator safety injection line).

Background:

LRA Section 4.3.2.10 states that the fatigue analysis for the welded attachments to Class 2 and Class 3 piping demonstrate a CUF of less than 1.0 during the period of extended operation.

The applicant dispositioned this time-limited aging analysis (TLAA) in accordance with 10 CFR 54.21 (c)(1 )(ii), stating that the fatigue analyses that support the elimination of arbitrary intermediate break locations, other than those for the charging system and the main feedwater system, demonstrate a CUF less than 1.0 during the period of extended operation.

Issue:

LRA Section 4.3.2.10 did not provide the 40-year CUF and corresponding 60-year projected CUF values for the integral pipe supports, other than those for the charging system and the main feedwater system, to support the applicant's disposition in accordance with 10 CFR 54.21 (c)( 1 )(ii); therefore, the staff cannot verify the adequacy of the applicant's TLAA disposition.

Request:

Provide the 40-year CUF and corresponding 60-year projected CUF values in the fatigue analysis for those welded attachments to Class 2 and Class 3 piping and justify that it supports the disposition for this TLAA in accordance with 10 CFR 54.21 (c)(1 )(ii), in that the analyses have been prOjected to the end of the period of extended operation.

-13 4.3-4

Background:

LRA Section 4.3.6 describes the fatigue TLAA of ASME Code Section III, metal bellows and expansion joints. The applicant stated that the analyzed numbers of cycles for all but seven of the diesel generator cooling water expansion joints are greater than the specified numbers of cycles extrapolated to 60 years; therefore the analyses are valid for these bellows through the period of extended operation and were dispositioned in accordance with 10 CFR 54.21 (c)(1)(i).

Issue:

For the diesel generator cooling water expansion joints that are dispositioned in accordance with 10 CFR 54.21(c)(1)(i), the applicant did not provide the number of analyzed cycles and the specified numbers of cycles extrapolated to 60 years to justify this disposition.

• The staff noted that LRA Table 3.3.2-4 provides an aging management review (AMR) line item for nickel alloy expansion joints exposed to raw water and subject to cumulative fatigue damage in the essential cooling water and essential cooling water wash system, which is managed by a TLAA. The staff reviewed LRA Section 4.3 and it was not clear to the staff which specific TLAA is being credited to manage cumulative fatigue damage for this particular AMR line item.

Request:

Provide the analyzed cycles and the specified number of cycles extrapolated to 60 years for the diesel generator cooling water expansion joints and justify the disposition of this TLAA in accordance with 10 CFR 54.21 (c)(1)(i).

• Clarify the fatigue TLAA that is being credited to manage cumulative fatigue damage for the nickel alloy expansion joints identified by the AMR line item in LRA Table 3.3.2-4. If the fatigue TLAA is not discussed in LRA Section 4, justify why the TLAA was not identified and dis positioned in accordance with 10 CFR 54.21 (c)(1). In lieu of a justification, amend the LRA to include the appropriate fatigue TLAAs, including the disposition in accordance with 10 CFR 54.21 (c)(1) with sufficient justification that supports this disposition.

4.3-5

Background:

LRA Section 4.3.2.12 states that, as a result of the replacement steam generator project, the main feedwater control valves were analyzed for a new set of operating design transient conditions, and it was found that they could not be qualified for the full number of loading and unloading transients defined for the life of the plant. To obtain acceptable fatigue limits the number of loadings and unloadings between 15 and 100 percent power had to be reduced from

- 14 13,200 to 10,300 for Unit 2. In addition, this limit does not apply to design of the Unit 1 feedwater control valves.

The applicant stated that it had experienced 62 occurrences of this transient for Unit 1 and 43 occurrences for Unit 2 through July 27, 1989, both of which were less than the 385 cycles anticipated at that point in the design life. The applicant projected 3,366 events to occur over 60 years and stated that this demonstrates a large margin between the analyzed value of 10,300; therefore, this TLAA was dispositioned in accordance with 10 CFR 54.21 (c)(1)(i), the fatigue analysis for the feedwater control valves is valid for the period of extended operation. The applicant stated that the loading and unloading events are the largest contributor to fatigue in the feedwater control valves, and that all other transients contribute 0.055 to the 40-year CUF.

The staff noted that the Operating License for Unit 1 was issued on March 22, 1988, and on March 28, 1989, for Unit 2. LRA Table 4.3-2 provides the "Program Limiting Value" for the unit loading and unloading transients (Transients NO.5 and No.6) of 3000 for Unit 1 and 10,300 for Unit 2.

Issue:

It is not clear to the staff whether the use of the 16-month (from March, 1988 to July, 1989) data for Unit 1 and 4-month (March 28, 1989 to July 27, 1989) data for Unit 2 to extrapolate the number of occurrences of unit loading and unloading transients for 60 years is conservative. It is also not clear how the applicant determined that 385 cycles of these transients were anticipated to occur through July 27, 1989.

The staff noted that the estimated occurrences of 3,366 cycles for these transients exceeds the "Program Limiting Value" of 3,000, which demonstrates that the applicant's disposition of this TLAA in accordance with 10 CFR 54.21 (c)(1 )(i) is not valid. In addition, the staff noted that the CUF contribution to the fatigue in the feedwater control valves by the unit loading and unloading transients was not included in the LRA.

Request:

• Justify that the use of data from initial plant operation to July 1989 for Unit 1 and data from initial plant operation to July 1989 for Unit 2 to estimate the number of occurrences for 60-years is conservative. Describe and justify how the 385 cycles of the unit loading and unloading transients that were anticipated to occur through July 27, 1989 was determined for Unit 1 and 2.

• Justify that the disposition in accordance with 10 CFR 54.21 (c)(1)(i) for the fatigue TL.AA of the Unit 1 Class 3 Feedwater Control Valves designed to Class 1 methods is appropriate, when considering the 60-year projected cycles of the unit loading and unloading transient (3,366 cycles) exceeds the "Program Limiting Value" of 3,000 cycles.

Provide the CUF contribution for the loading and unloading transients on the feedwater control valves.

- 15 4.3-6

Background:

LRA Table 4.3-8 indicates that, for the hot leg surge nozzle, the 40-year CUF, the 40-year environmentally-assisted fatigue (EAF) CUF, and the 60-year EAF CUF are 0.8196,7.5904, and 11.3856 respectively. LRA Table 4.3-8 also indicates that, for the charging system nozzle (normal line and alternate line), the 40-year CUF, 40-year EAF CUF, and 60-year EAF CUF are 0.19814, 1.5585, and 2.3378 respectively.

Issue:

During its audit, the staff found that the CUF and EAF CUF values for these nozzles in the applicant's basis documents are different from those in the LRA Table 4.3-8.

Reguest:

Revise LRA Table 4.3-8 to provide correct CUF and EAF CUF values that are consistent with the basis documents for the Hot Leg Surge Nozzle and Charging System Nozzles.

Confirm that the remaining information in LRA Table 4.3-8 is accurate. If not, provide the appropriate revisions.

4.3-7

Background:

LRA Section 4.3.4 describes three methods that were used to reduce the EAF CUF values:

(1) recalculating the CUF with a more accurate fatigue analysis; (2) using projected values of the accumulated number of transient events, instead of using the 40-year number of events; and (3) calculating an average Fen using strain-rate dependent Fen values for load set pairs significant to fatigue and using the maximum Fen for load set pairs not significant to fatigue.

Issue:

Based on the information in LRA Section 4.3.4, the staff cannot determine what constitutes a "more accurate fatigue analysis," how it was performed and what conservatism was removed to obtain reduced EAF CUF values. The staff also cannot identify the locations in LRA Table 4.3-8 that used these three methods, described above, to reduce conservatism to obtain reduced EAF CUF values.

Reguest:

For those locations listed in LRA Table 4.3-8, identify the components and the associated methods described above that were used to reduce the EAF CUF values.

4.3-8

- 16

• For each location, describe and justify the techniques used in performing the "more accurate fatigue analysis," and how any conservatism was removed to reduce the EAF CUF.

Background:

LRA Section 4.3.2.1 states that the maximum usage factor based on the design number of transient cycles in the reactor studs is 0.3372, and for the stud hole inserts is 0.8852. The applicant stated that the effects of cumulative fatigue damage will be managed during the period of extended operation using its Metal Fatigue of Reactor Coolant Pressure Boundary Program.

In its review of the applicant's operating experience during the audit, the staff noted that a work order dated April 12, 2007, indicates that an ASME Code Section XI, replacement of the #30 ROTO*LOK stud was conducted in Unit 2 during Refueling Outage 12. The associated design change package, dated April 9, 2007, indicates that Stud #30 of Unit 2 had rotated inadvertently during the de-tensioning process causing it to partially engage inside the stud hole insert, and that this condition caused damage to Stud #30, which was partially engaged. The design change package also indicates that the applicant decided to replace Stud #30 of Unit 2 with a spare stud of the same kind. Based on an evaluation performed on the stud hole insert, the applicant determined that the non-conforming condition of the stud insert was dispositioned as "Use-As-Is." The applicant's design change package further indicates that the damaged areas of the stud hole insert bearing surfaces are conservatively estimated to be 17% of the original area of contact.

Issue:

The staff noted that the reduced load bearing surfaces of the partially damaged (rolled) stud hole insert increases the stress level applied to the studs and the stud hole insert, which may affect assumptions used in the fatigue analyses of the reactor vessel head components. It is not clear to the staff whether the TLAA disposition in accordance with 10 CFR 54.21 (c){1){iii) for the reactor vessel closure head studs in LRA Section 4.3.2.1 considered the effect of the damaged stud hole insert.

Request:

Clarify and justify whether the assumptions and results of the fatigue analyses of the reactor vessel head components remain valid, when considering the operating experience related to the stud hole insert described above. In addition, discuss whether the damaged stud hole insert affects the number of analyzed design transients that were determined in the fatigue analyses.

Clarify the fatigue analyses and the associated components that are affected by the damaged stud hole insert and justify that the effect of the cumulative fatigue damage of these components, considering the existence of the damage stud hole insert, will be managed for the period of extended operation.

4.3-9

- 17

Background:

As described in UFSAR Section 3.9.1.1.8, the small loss-of-coolant accident, small steam line break, and complete loss of flow are system transients and are considered emergency conditions. LRA Sections 4.3.2.7 and A3.2.1. 7 state that the TLAA disposition for ASME Code Section III, Class 1 piping and piping nozzles is in accordance with 10 CFR 54.21 (c)(1)(iii). The LRA sections also indicate that the fatigue usage factors in these components do not depend on effects that are time-dependent at steady-state conditions, but depend only on effects of normal, upset, and emergency transient events. LRA Sections 4.3.3 and A3.2.2 state that the TLAA disposition for the reactor vessel internals is in accordance with 10 CFR 54.21 (c)(1)(iii) and indicate that the fatigue usage factors in these components do not depend on effects that are time-dependent at steady-state conditions, but depend only on effects of normal, upset, and emergency transient events. The applicant also stated that the Metal Fatigue of Reactor Coolant Pressure Boundary Program described in LRA Section 4.3.1 and B3.1 ensures that the numbers of transients actually experienced during the period of extended operation remain below the assumed number.

Issue:

LRA Section 4.3.1.1 indicates that the Metal Fatigue of Reactor Coolant Pressure Boundary Program does not monitor emergency and faulted conditions. LRA Table 4.3-2 also does not include the three emergency conditions listed above. It is not clear to the staff: (1) if LRA Table 4.3-2 includes all transients that were used in these fatigue analyses; and (2) whether the three transients identified as emergency conditions, in UFSAR Section 3.9.1.1.8, will be monitored by the Metal Fatigue of Reactor Coolant Pressure Boundary Program.

Reguest:

Clarify whether emergency conditions are included into the fatigue analyses for ASME Code Section III, Class 1 piping and piping nozzles and the reactor vessel internals. If so, justify why the Metal Fatigue of Reactor Coolant Pressure Boundary Program does not monitor emergency transients. If not, clarify why the dispositions for the fatigue analyses of ASME Code Section III, Class 1 piping and piping nozzles and the reactor vessel internals in the aforementioned LRA Sections discuss emergency transients. If necessary, revise the LRA accordingly.

4.3-10

Background:

LRA Section 4.3.4 states that, despite efforts to reduce the EAF CUF below 1.0, the EAF CUFs for the hot leg surge nozzle and charging nozzles are projected to exceed 1.0 within 60 years of operation. Corrective action for these locations will be required under the Metal Fatigue of Reactor Pressure Boundary Program when the cycle-based fatigue (CBF) results, including the effects of the reactor coolant environment, indicate that a fatigue based action limit has been

4.3-11

- 18 reached. LRA Section 4.3.4 also describes several methods that the applicant took to remove conservatism and reduce the EAF CUF values.

LRA Table 4.3-1 indicates that the stainless steel hot leg surge nozzle (safe end) and charging system nozzle (normal and alternate line) are NUREG/CR-6260 locations that will be monitored by the Metal Fatigue of Reactor Coolant Pressure Boundary Program with the CBF monitoring method. LRA Table 4.3-8 provides the 60-Year EAF CUF of 11.3856 for the hot leg surge nozzle (safe end) and 2.3378 for the charging system nozzle (normal and alternate line).

Issue:

In the closure of GSI-190, the staff determined that the risk from fatigue failure of the primary coolant pressure boundary components is very small for a plant life of 40 years; however, since conservatism has already been removed to calculate the 60-year EAF CUF for the hot leg surge nozzle and charging system nozzle, which still exceed the Code design limit of 1.0, it is not clear to the staff how the applicant will manage fatigue with its Metal Fatigue of Reactor Coolant Pressure Boundary Program.

Request:

When considering that conservatism has already been removed to obtain 60-year EAF CUF values for the hot leg surge nozzle and charging system nozzle, which still exceed the Code design limit of 1.0, describe how the Metal Fatigue of Reactor Coolant Pressure Boundary Program will manage fatigue of these components for the period of extended operation, when considering environmental effects. As part of the explanation, describe the CBF action limits for these components and the corrective actions that may be taken or have been taken.

Background:

LRA Section 4.3.1.2 states that the occurrences of the transients listed in LRA Table 4.3-2 are tracked and the CUFs at the locations listed in LRA Table 4.3-1 are managed using either the cycle counting (CC) monitoring method or the cycle-based fatigue (CBF) monitoring method. In addition, it states the most limiting number of cycles for each transient is listed as the "Program Limiting Value" and will be used for the Metal Fatigue of Reactor Coolant Pressure Boundary Program as listed in LRA Table 4.3-2.

LRA Section 4.3.1.3 states that the locations listed in LRA Table 4.3-1, "Summary of CBF Monitored Locations in the STP Fatigue Management Program," will be monitored for fatigue usage using the CBF monitoring method.

LRA Section 4.3.4 states that a method used to reduce the EAF CUF values includes using projected values of the accumulated number of transient events, which are provided in LRA Table 4.3-2, instead of using the 40-year number of events.

- 19 Issue:

Based on the information from LRA Sections 4.3.1.2,4.3.1.3,4.3.4, and LRA Tables 4.3-1 and 4.3-2, the following is not clear to the staff:

• Are the components identified in LRA Table 4.3-1 monitored by CC, CBF or a combination of the monitoring methods.

• Are the components identified in LRA Table 4.3-1 the only ones monitored by the Metal Fatigue of Reactor Coolant Pressure Boundary Program to manage cumulative fatigue damage.

• Are there other TLAAs that use the 60-year projected cycles from LRA Table 4.3-2, other than the EAF evaluations, and does the Metal Fatigue of Reactor Coolant Pressure Boundary Program account for the use of these cycles when using the CC monitoring method.

In addition, the staff noted that LRA Table 4.3-1 did not mention several components and their TLAAs (e.g., reactor vessel internals, pressurizer, steam generator, residual heat removal valves) that were dispositioned in accordance with 10 CFR 54.21 (c)( 1 )(iii); therefore it is not clear which monitoring method will be used by the Metal Fatigue of Reactor Coolant Pressure Boundary Program to manage cumulative fatigue damage of these components.

Request:

• Clarify the monitoring method used by the Metal Fatigue of Reactor Coolant Pressure Boundary Program to manage cumulative fatigue damage for the componentsllocations and their TLAAs discussed in LRA Section 4.3 that were dis positioned in accordance with 10 CFR 54.21 (c)(1 )(iii). If necessary, provide the appropriate revisions to the LRA.

If there are any TLAAs that use the 60-year projected cycles other than the EAF evaluations, clarify if the Metal Fatigue of Reactor Coolant Pressure Boundary Program accounts for the use of these cycles in the CC monitoring method. In addition, justify that the Metal Fatigue of Reactor Coolant Pressure Boundary Program will ensure that these TLAAs remain valid and that cumulative fatigue damage will be adequately managed through the period of extended operation.

4.3-12

Background:

LRA Section 4.3.1.3 states that the applicant captured all the necessary transient events, and that the event history was taken primarily from existing manual or computer-assisted cycle counting records. In addition, the LRA states that the procedures at the site define the tracking requirements and record the plant cyclic transients.

- 20 LRA Section 4.3.1.3 also states that the baseline cycle counting results were projected to 60 years, and that the projected cycle counts were computed based on the actual accumulation history since the start of plant life. In addition, the cycle projections are based on a long term weighting (L TW) and short term weighting (STW) to obtain the most accurate projections of the future behavior of that event.

LRA Section 4.3.4 states that a method used to reduce the EAF CUF values includes using projected values of the accumulated number of transient events, which are provided in LRA Table 4.3-2, instead of using the 40-year number of events.

Issue:

It is not clear to the staff if, during the applicant's review of the transient event history, the applicant confirmed that the severity of the transients that occurred were bounded by the severity of the design transient.

In addition, since the applicant used the 60-year transient projections in its EAF fatigue analyses, additional information is needed about the L TW and STW used by the applicant in its projection methodology for the staff to determine if it was appropriate and conservative.

Request:

During the applicant's review of the transient event history, confirm that the severity of all transients that have occurred is bounded by the design severity of the transient. If not, describe the actions taken when the severity of an actual transient exceeded the design severity of the transient. Describe how the Metal Fatigue of Reactor Coolant Pressure Boundary Program ensures that the design severity of a transient is not exceeded.

Describe the L TW and STW used for the 60-year projection methodology of design transients listed in LRA Table 4.3-2. In addition, justify that this 60-year projection methodology is conservative. Identify the transients in LRA Table 4.3-2 to which the LTW and STW are applicable and identify the L TW and STW values.

If any design transient in LRA Table 4.3-2 used a different 60-year projection methodology, other than the one discussed above (long and short term weighting),

describe and justify that this "alternative" 60-year projection methodology is conservative.

- 21 4.3-13

Background:

LRA Section 4.3.1.2 states that the Metal Fatigue of Reactor Coolant Pressure Boundary Program tracks the occurrences of the transients listed in LRA Table 4.3-2.

The following transients are listed in LRA Table 4.3-2:

Transient 5, "Unit Loading at 5% of Full Power/min"

• Transient 6, "Unit Unloading at 5% of Full Power/min" Transient 10, "Steady State Fluctuations, Initial" Transient 11, "Steady State Fluctuations, Random" Transient 15, "Unit Loading Between 0-15% of Full Power"

• Transient 16, "Unit Unloading Between 0-15% of Full Power" Transient 17, "Boron Concentration Equalization" LRA Table 4.3-2 also provides the following footnotes:

Footnote 2 - Transients 10 and 11 "Steady State Fluctuations" are listed in UFSAR Table 3.9-8; however they are not projected and are marked as "NP." These transients do not have a significant effect on fatigue and are bounded by transients which are tracked.

Footnote 5 - Transient 17 "Boron Concentration Equalization" is listed in UFSAR Table 3.9-8; however it is not projected and marked as "NP." This transient is bounded by load change transients which are tracked.

LRA Section 4.3.4 states that a method used to reduce the EAF CUF values included using projected values of the accumulated number of transient events, which are provided in LRA Table 4.3-2, instead of using the 40-year number of events.

Issue:

For all the transients listed above, LRA Table 4.3-2 does not provide a baseline number of cycles for Units 1 and 2; therefore it is not clear how the Metal Fatigue of Reactor Coolant Pressure Boundary Program tracks the occurrences of the transients.

For Transients 10 and 11, it is not clear how the applicant determined that these transients do not have a significant effect on fatigue. It is also not clear which transients are tracked by the applicant and how they bound Transients 10 and 11.

Based on footnote 5, it is not clear which load change transients that are tracked by the Metal Fatigue of Reactor Coolant Pressure Boundary Program bound Transient 17.

Since 60-year projections were not provided for the transients listed above, it is not clear whether they were included into the applicant's EAF CUF calculations.

- 22 Reguest:

Justify how the Metal Fatigue of Reactor Coolant Pressure Boundary Program tracks the occurrences of the Transients 5, 6, 10, 11, 15, 16, and 17 without having a baseline number of cycles.

Justify why Transients 10 and 11 do not have a significant effect on fatigue. Identify the tracked transients that bound Transients 10 and 11 and justify how these tracked transients bound Transients 10 and 11.

Clarify the load change transients that are tracked by the Metal Fatigue of Reactor Coolant Pressure Boundary Program that bound Transient 17. Describe and justify how these tracked load change transients bound Transient 17.

Clarify whether Transients 5, 6, 10, 11, 15, 16, and 17 were included into the EAF CUF calculations. If they were included, provide the number of cycles that were used in these calculations. If not, justify why these transients can be excluded from the EAF CUF calculations.

4.3-14

Background:

LRA Table 4.3-2 provides the following information for these selected transients:

Baseline Events Projected Transient Description up to Year end events for 60 2008 Unit 1 Unit 2 19 - Primary Side Leak Test 1

0 22 - Turbine Roll Test 9

5 43 - Primary Side Hydrostatic Test 1

1 1

1 44 - Secondary Side Hydrostatic Test 1

1 1

1 (each generator)

LRA Section 4.3.4 states that a method used to reduce the EAF CUF values includes using projected values of the accumulated number of transient events, which are provided in LRA Table 4.3-2, instead of using the 40-year number of events.

Issue:

For the transients listed above, LRA Table 4.3-2 indicates that these transients are not expected to occur again through 60 years of operation, except Transient 19 for Unit 2. Since these projections may have been used in reducing the EAF CUF, it is not clear why these transients are not expected to occur again and whether this is conservative.

- 23 Request:

• Justify why Transients 19 (except for Unit 2), 22,43, and 44 are not expected to occur again through 60 years of operation. In addition, explain why one cycle of Transient 19 for Unit 2 is expected to occur when no additional cycles of this transient are expected for Unit 1.

• Justify that the use of these projections are conservative for the EAF CUF calculations.

If these projections were not used, clarify the number of cycles used for Transients 19, 22, 43, and 44 in the EAF CUF calculations.

4.3-15

Background:

LRA Section 4.3.2.3 states that the reactor coolant pumps (RCP) for both units were designed to the Class 1 reqUirements of ASME Code Section III, 1971, with addenda through the summer 1973. Furthermore, the fatigue analyses for the RCPs were performed with transients provided in UFSAR Table 3.9-8, with additional cooling water and seal injection transients. The LRA also states that these analyses demonstrated code compliance for most reactor coolant pump components by satisfying the six criteria for a fatigue waiver per NB-3222.4(d).

LRA Section 4.3.2.3 also states that the TLAAs for the RCP pressure-retaining components are dispositioned in accordance with 10 CFR 45.21 (c)(1 )(iii), and that the Metal Fatigue of Reactor Coolant Pressure Boundary Program will manage effects of fatigue for the period of extended operation.

Issue:

It is not clear from the information provided in LRA Sections 4.3.2.3 and B3.1, how the applicant's Metal Fatigue of Reactor Coolant Pressure Boundary Program will ensure that the fatigue waiver for RCP pressure-retaining components will remain valid during the period of extended operation. It is also not clear to the staff if the number of design cycles provided in UFSAR Table 3.9-8 were used in the applicant's analyses to demonstrate that the criteria for a fatigue waiver per NB-3222.4(d) were satisfied.

Reguest:

Specific to those RCP components and associated TLAAs that satisfied the six criteria for a fatigue waiver per NB-3222.4(d), describe how the Metal Fatigue of Reactor Coolant Pressure Boundary Program will manage the effects of cumulative fatigue damage through the period of extended operation.

- 24 4.3-16

Background:

LRA Section 4.3.2.5 states that the analyses of the replacement steam generators (RSG) show that the usage factors of the steam generator components are less than the allowable 1.0, as shown in LRA Table 4.3-5, except for the manway studs, which were qualified by fatigue tests.

LRA Table 4.3-5 states that the cumulative usage factor for the primary manway studs for Unit 1 and 2 is 7.13 and is denoted with footnote 1, which states that fatigue usage exceeds the allowable of 1.0 and is qualified for 40 years by fatigue testing.

This LRA section also states that the fatigue usage factors in the replacement steam generator components do not depend on effects that are time dependent at steady-state conditions, but depend only on effects of operational, abnormal, and upset transient events. The applicant dispositioned the TLAAs for the RSGs in accordance with 10 CFR 54.21(c)(1)(iii), such that effects of fatigue for the replacement steam generator components will be managed for the period of extended operation with the Metal Fatigue of Reactor Coolant Pressure Boundary Program.

Issue:

LRA Section 4.3.2.5 did not describe the details of the fatigue testing that was performed to qualify the primary manway studs for the Unit 1 and 2 RSGs. Therefore, it is not clear to the staff how the applicant will use its Metal Fatigue of Reactor Coolant Pressure Boundary Program to manage cumulative fatigue damage of the primary manway studs, since they were described as qualified by fatigue testing.

Request:

Describe how the primary manway studs for the Unit 1 and 2 RSGs were qualified for 40-years by fatigue testing. Identify sections of the applicable design codes that were used for the fatigue testing.

Describe and justify how the Metal Fatigue of Reactor Coolant Pressure Boundary Program will manage cumulative fatigue damage of the primary manway studs for the Unit 1 and 2 RSGs.

4.3-17

Background:

LRA Section 4.3.3 discusses the applicant's ASME Code Section III, Subsection NG, fatigue analysis of reactor pressure vessel internals. The applicant stated that Westinghouse evaluated the Unit 1 and 2 reactor vessel internals for the effects of the 1.4% uprating and that the assessment of core support structures' limiting margins of safety and fatigue usage factors resulted in meeting ASME Code allowable values as shown in LRA Table 4.3-7.

- 25 LRA Table 4.3-7 provides the limiting 40-Year CUF for Unit 1 and 2 of the "baffle, former assembly," which is <1 (test).

The applicant dis positioned the TLMs in accordance with 10 CFR 54.21 (c)(1 )(iii), such that effects of fatigue for the reactor vessel internals will be managed for the period of extended operation with the Metal Fatigue of Reactor Coolant Pressure Boundary Program.

Issue:

LRA Section 4.3.3 did not describe the details of the test that was performed to determine that the CUF for the "baffle, former assembly" to be less than one. In addition, it is not clear to the staff how the applicant will use its Metal Fatigue of Reactor Coolant Pressure Boundary Program to manage cumulative fatigue damage of the "baffle, former assembly," since the CUF is shown to be less than 1 by testing.

Request:

Describe how the CUF for the "baffle, former assembly" for Unit 1 and 2 were shown to be less than 1 by testing. Identify sections of the applicable design codes that were used for the fatigue testing.

Describe and justify how the Metal Fatigue of Reactor Coolant Pressure Boundary Program will manage cumulative fatigue damage of the "baffle, former assembly" for Unit 1 and 2, since the CUF was shown to be less than 1 by testing.

4.3-18

Background:

LRA Section 4.3.5 discusses the TLMs associated with assumed thermal cycle count for allowable secondary stress range reduction factor in ANSI B31.1 and ASME Code Section III, Class 2 and 3 piping. The LRA states that these are dispositioned in accordance with 10 CFR 54.21 (c)(1)(i), and that the existing analyses of piping for which the allowable range of secondary stresses depends on the number of assumed thermal cycles and that are within the scope of license renewal are valid for the period of extended operation.

LRA Section 4.3.5 also states that temperature screening criteria (less than 220°F in carbon steel components and less than 270°F in stainless steel components) were used to identify components that might be subject to significant thermal fatigue effects.

- 26 The applicant stated:

[A] systematic survey of all plant piping systems found that the piping and components in the scope of license renewal:

Do not meet the operating temperature screening criteria, and therefore do not experience significant thermal cycle stresses; or Clearly do not operate in a cycling mode that would expose the piping to more than three thermal cycles per week, i.e. to more than 7,000 cycles in 60 years; or

• The assumed thermal cycle count for the analyses depends closely on reactor operating cycles, and can therefore conservatively be approximated by the thermal cycles used in the ASME Section III Class 1 vessel and piping fatigue analyses.

10 CFR 54.21 (a}(1) states that, for those systems, structures, and components within the scope of 10 CFR 54.4, structures and components subject to an aging management review are to be identified and listed. Additional requirements for those structures and components that are subject to an aging management review are described in 10 CFR 54.21 (a}(1 }(i) and 10 CFR 54.21 (a)(1)(ii).

Issue:

The staff reviewed the applicant's AMR results in the associated LRA Tables (3.x.2-y) in LRA Sections 3.2, 3.3 and 3.4, and noted that they did not include the applicable AMR line items for the TLAAs associated with fatigue of non-Class 1 piping. It is not clear to the staff why the components analyzed for cumulative fatigue damage by the TLAAs discussed in LRA Section 4.3.5 are not included as AMR line items in LRA Sections 3.2, 3.3 and 3.4.

The staff noted that the applicant's results from its "systematic survey of all plant piping systems" do not permit the exclusion of structures and components from an aging management review and that the structures and components must still be listed and identified for aging management review in accordance with 10 CFR 54.21(a)(1).

Request:

Clarify whether the techniques from the "systematic survey of all plant piping systems" were used to exclude AMR line items from LRA Tables (3.x.2-y) in LRA Sections 3.2, 3.3, and 3.4.

If yes, justify how the use of this systematic survey satisfies 10 CFR 54.21 (a)(1) or revise the applicable LRA Tables (3.x.2-y) in LRA Sections 3.2, 3.3, and 3.4 to include the AMR line items that address cumulative fatigue damage for non-Class 1 piping.

- 27 If no, explain why there are no AMR line items in LRA Sections 3.2, 3.3, and 3.4 that are associated with the TLAA for ANSI B31.1 and ASME Code Section III, Class 2 and 3 piping discussed in LRA Section 4.3.5.

4.3-19

Background:

LRA Section 4.3.4 states that the RPV Wall Transition, RPV Inlet Nozzle, and RPV Outlet Nozzle have a 60-year EAF CUF less than 1.0 when multiplied by the maximum applicable Fen value for low-alloy steels. The Fen value for the material was determined based on NUREG/CR-6583, "Effects of LWR Coolant Environments on Fatigue Design Curves of Carbon and Low-Alloy Steels." LRA Table 4.3-8 provides a Fen value of 2.455 for these low-alloy steel components.

Issue:

The staff noted that based on the guidance in NUREG/CR-6583 the Fen value is dependent on sulfur content, temperature, dissolved oxygen, and strain rate. In addition, the Fen value can vary significantly depending on dissolved oxygen content at the applicant's site. It is not clear to the staff what assumptions were used by the applicant in determining the Fen values for the low alloy steel components.

Reguest:

• Clarify how the Fen values for the low-alloy steel components were determined and justify any assumptions on the parameters, such as sulfur content, temperature, dissolved oxygen, and strain rate, which were used. As part of the justification, confirm that the dissolved oxygen remained less than 0.05 ppm since initial plant operation. If it has not, justify that the Fen value of 2.455 is conservative and appropriate for the conditions at the plant.

• Justify that the dissolved oxygen content will remain less than 0.05 ppm during the period of extended operation, such that the Fen values are bounding for the conditions at the plant for the low-alloy steel components.

4.3-20

Background:

LRA Section 4.3.2.10 states that the fatigue crack growth analyses for the pressurizer surge line and accumulator safety injection lines established that flaws would not reach the flaw depths allowed in paragraph IWB-3640 of the ASME Code during the plant life. The applicant also stated that the analyses that evaluated fatigue crack growth and cumulative usage factor in the pressurizer surge line and the accumulator safety injection line depend on the standard number of cycles for a 40-year reactor lifetime. Therefore these analyses are TLAAs.

4.3-21

- 28 Issue:

The staff noted that LRA Section 4.3.2.10 provides two TLAA dispositions: "Projection, 10 CFR 54.21 (c)(1)(ii); and Aging Management, 10 CFR 54.21 (c)(1)(iii}." However, it is not clear to the staff how the analyses that evaluated fatigue crack growth for the pressurizer surge line and accumulator safety injection lines were dispositioned.

Specifically, for the disposition in accordance with 10 CFR 54.21 (c)(1 )(ii), the applicant did not provide any information to justify that these analyses have been projected to the end of the period of extended operation.

In addition, for the disposition 10 CFR 54.21 (c)(1)(iii), the staff noted that the applicant's Fatigue Monitoring Program is based on GALL AMP X.M1, which is limited to the use of cycle counting for CUF analyses (e.g. ASME Code Section III, CUF analyses and environmentally-assisted CUF analyses); therefore, the use of cycle counting to manage crack growth is not covered by GALL AMP X.M1. The staff also noted that enhancements to the applicable program elements (e.g. "scope of program," "parameters monitored or inspected," "monitoring and trending,"

"acceptance criteria," or "corrective action") are needed to provide justification for all cycle counting design transients that were assumed in the fatigue crack growth analysis.

Reguest:

Provide the TLAA disposition for the analyses that evaluated fatigue crack growth of the pressurizer surge line and the accumulator safety injection lines.

If the TLAA is dispositioned in accordance with 10 CFR 54.21 (c)(1)(i) or 10 CFR 54.21 (c)(1 )(ii), provide sufficient information related to the fatigue crack growth analyses to justify the selected disposition.

If the TLAA is dispositioned in accordance with 10 CFR 54.21 (c)(1 )(iii) and the Metal Fatigue of Reactor Coolant Pressure Boundary Program will be used, justify the use of cycle counting for these fatigue crack growth analyses without an update to the cycle counting procedure and the inclusion of enhancements to the applicable program elements.

Background:

LRA Section 4.3.2.8 states that any supporting fatigue analyses related to thermal cycling for normal charging, alternate charging, and the auxiliary spray lines are not TLAAs in accordance with 10 CFR 54.3(a), Criterion 3, in that the fatigue analyses did not involve a time-limited assumption.

- 29 Issue:

In the staff's safety evaluation (SE) related to the resolution of Bulletin 88-08, dated May 6, 1998 (ADAMS Legacy Accession Number 9805110004), the applicant estimated that the ASME CUF limit of 1.0, when considering design transients and inadvertent thermal stratification cycling, would be achieved in a time span of 11.4 years based on a fatigue evaluation, performed by Westinghouse, of the weld between the check valve and the unisolable piping. In this SE, the staff noted that the time span was calculated using the assumption that thermal cycling occurred at the check valve weld and that the ASME CUF limit would not be achieved at the weld during the life of the plant (40 years) without the assumption of thermal cycling. It is not clear to the staff why the fatigue analyses performed by the applicant, which included time-limited assumptions, would not be defined as a TLAA, in accordance with 10 CFR 54.3(a).

Request:

Based on the staff's SE dated May 6, 1998, justify why the fatigue analyses related to thermal cycling were not identified as TLAAs, as defined in 10 CFR 54.3(a). Or provide and justify the TLAA disposition for the fatigue analyses of the weld between the check valve and the unisolable piping related to thermal cycling for the normal charging, alternate charging, and the auxiliary spray lines.

RAI4.3-22

Background:

LRA Section 4.3.2.6 provides the TLAA for ASME Code Section III, Class 1 valves and LRA Table 4.3-6 provides a summary of the applicant's Class 1 valve fatigue analyses. The applicant dispositioned the following Class 1 valves in accordance with 10 CFR 54.21 (c)(1 )(ii),

that the design of these valves for fatigue is valid for the period of extended operation:

6 inch pressurizer safety relief valves 6 inch hi-head safety injection pump discharge check valves 8 inch hi-head safety injection pump discharge cheCk valves 8 inch lo-head safety injection to hot leg check valves 12 inch safety injection to cold leg injection check valves 12 inch safety injection accumulator outlet valves 2 inch CVCS auxiliary spray check valves 2 inch RCP seal injection first check valves 2 inch RCP seal injection second check valves The applicant dispositioned the 12 inch RHR pump suction isolation valves in accordance with 10 CFR 54.21(c)(1)(iii), that the aging effects of the Class 1 valve pressure boundaries will be managed for the period of extended operation by the Metal Fatigue of Reactor Coolant Pressure Boundary Program.

- 30 Issue:

The staff noted that LRA Table 4.3-6 provides the fatigue results for the "8 inch Lo Head Safety Injection Train AlBIC To Loop 1 (2)AlB/C Cold Leg Check Valve" and the "3 inch X 6 inch Pressurizer Power Operated Relief Valve," but does not provide a disposition for these valves.

Therefore, it is not clear how the applicant has dispositioned the TLAAs for these valves in accordance with 10 CFR 54.21(c)(1).

Request:

Provide and justify the dispositions for the fatigue TLAA of the "8 inch Lo Head Safety Injection Train AlBIC To Loop 1 (2)AlB/C Cold Leg Check Valve" and the "3 inch X 6 inch Pressurizer Power Operated Relief Valve," in accordance with 10 CFR 54.21 (c)(1). Provide the appropriate revisions to LRA Section 4 and Appendix A.

Aluminum (070)

RAI 3.2.1.50-1

Background:

LRA Table 3.3.2-17, page 3.3-181, includes an AMR item for a carbon steel valve exposed to fuel oil. The AMR item states that there is no aging effect requiring management and no AMP is proposed. The AMR item references LRA Table 3.2.1, item 3.2.1-50, and cites generic note A.

However, item 3.2.1-50 is for aluminum components exposed to indoor uncontrolled air, not for carbon steel components exposed to fuel oil.

The GALL Report, Revision 2, items VII.H1.AP-105 and VII.H2.AP-105, state that carbon steel piping, piping components, piping elements, and tanks exposed to fuel oil are susceptible to loss of material and recommend GALL AMP XI.M30, "Fuel Oil Chemistry," and XI.M32, "One-time Inspection," to manage the aging effect.

Issue:

The references to LRA Table 3.2.1, item 3.2.1-50 and generic note A appear to be incorrect. It is unclear to the staff how this item is being appropriately managed for loss of material, as recommended by the GALL Report.

Request:

Revise the AM R item for the carbon steel valve exposed to fuel oil in LRA Table 3.3.2-17 to correct any errors in the line and to provide an appropriate AMP to manage loss of material; or explain why the valve is not susceptible to loss of material.

- 31 Cast Austenitic Stainless Steel (073)

RAI 3.1.1.80-1

Background:

The GALL Report, Revision 2, item IV.B2.RP-382, recommends that cracking or loss of material of the RVI core support structure, made of stainless steel, nickel alloy, and CASS, should be managed by GALL AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD." Examination Category B-N-3 in Table IWB-2500-1 of the 2004 edition of the ASME Code Section XI, specifies visual VT-3 examination of the removable core support structures.

The staff noted that the inspections in accordance with Examination Category B-N-3 of the ASME Code Section XI, can also provide indirect evidence of loss of fracture toughness.

LRA Table 3.1.1, item 3.1.1-80 addresses CASS reactor vessel internals (RVls), which are exposed to the reactor coolant and subject to loss of fracture toughness due to thermal aging and neutron irradiation embrittlement. LRA item 3.1.1-80 also indicates that the aging effect is not applicable based on EPRI 1016596, "Materials Reliability Program: Pressurized Water Reactor Internals Inspection and Evaluation Guidelines (MRP-227}," Revision 0, issued in December,2008. Specifically, LRA Table 3.1.2-1 states that, consistent with EPRI 1016596 (MRP-227), loss of fracture toughness is not an applicable aging effect requiring management for the RVI CASS upper core support - upper support column base.

In addition, LRA Table 3.1.2-1 addresses an AMR item to manage loss of material of the CASS upper core support - upper support column base using the Water Chemistry Program.

However, in comparison with the GALL Report, Revision 2, item IV.B2.RP-382, LRA Table 3.1.2-1 does not address an AMR item that uses the ASME Code Section Xllnservice Inspection, Subsections IWB, IWC, and IWD Program to manage cracking and loss of material of the upper support column base and the other core support structure components.

Issue:

LRA Table 3.1.2-1 does not address an AMR item that uses the ASME Section Xllnservice Inspection, Subsections IWB, IWC, and IWD Program to manage cracking and loss of material of the CASS upper support column base and the other core support structure components, even though the core support structure components made of stainless steel, nickel alloy, and CASS materials are susceptible to cracking and loss of material in the reactor coolant environment.

The GALL Report, Revision 2, item IV.B2.RP-382, recommends the ASME Section Xllnservice Inspection, Subsections IWB, IWC, and IWD Program to manage these aging effects.

Request:

Since the core support structures made of stainless steel, nickel alloy, and CASS materials are susceptible to cracking and loss of material in the reactor coolant environment, provide justification as to why LRA Table 3.1.2-1 does not identify an AMR item that uses the GALL Report recommendation of ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program to manage cracking and loss of material of the core support structures.

- 32 RAI 3.1.1.80-2

Background:

LRA Table 3.1.1, item 3.1.1-80, addresses loss of fracture toughness due to thermal aging and neutron irradiation embrittlement of CASS reactor vessel internals exposed to reactor coolant. It also states that this aging effect is not applicable based on MRP-227. LRA Section B2.1.35 states that the PWR Reactor Internals Program implements the guidance of EPRI1016596 (MRP-227) and EPRI 1016609, "Inspection Standard for PWR Internals (MRP-228),"

Revision 0. LRA Section B2.1.35 also states that the program manages aging consistent with the inspection guidance for Westinghouse designated primary components in Table 4-3 of MRP-227 and Westinghouse designated expansion components in Table 4-6 of MRP-227.

MRP-227, which is referenced in the GALL Report, Revision 2, categorizes the reactor vessel internal components to the following functional groups: primary, expansion, existing programs, and no additional measures. It also specifies relevant examination methods and coverage for the expansion group components based on the examination findings of the primary group components.

The GALL Report, Revision 2, items IV.B2.RP-297, IV.B2.RP-290, and IV.B2.RP-292, and MRP-227 Tables 3-3,4-3,4-6, and 5-3 indicate that in Westinghouse plants, the control rod guide tube (CRGT) assembly lower flanges made of CASS are subject to loss of fracture toughness and are the primary components that are linked to the following expansion components: (1) lower support assembly lower support column bodies made of CASS; and (2) bottom-mounted instrumentation (BMI) system BMI column bodies made of stainless steel.

Issue:

In contrast with the GALL Report, Revision 2 and MRP-227, LRA Table 3.1.2-1 does not identify the functional groups and link relationships (for example, primary/expansion relationship) for the following components: (1) CRGT assembly lower flanges; (2) lower support assembly lower support column bodies; and (3) BMI column bodies. The staff needs this information regarding the functional groups and link relationships in order to evaluate the adequacy of the applicant's aging management methods, because the examination methods and coverage for the expansion group components are based on the examination findings of the primary group components.

Request:

1. Describe the functional groups for the following components: (1) CRGT assembly lower flanges made of CASS; (2) lower support assembly lower support column bodies made of CASS; and (3) BMI column bodies made of stainless steel. In addition, describe the link relationships for these components (such as primary/expansion link).

If the assigned functional groups or links are not consistent with MRP-227 and the applicant's evaluation of its operating experience, justify why the inconsistency is acceptable to manage loss of fracture toughness of these components.

- 33

2. Revise LRA Table 3.1.2-1 and other related information in the LRA consistent with the applicant's response.

RAI 3.4.2.6-2

Background:

LRA Table 3.4.2-6 indicates that CASS valves exposed to atmosphere/weather have no aging effect requiring management; therefore, no aging management program is proposed for the components. LRA Table 3.0-1 indicates that the atmosphere/weather environment consists of moist. ambient temperatures, humidity, and exposure to weather, including precipitation and wind. It also indicates that the component is exposed to air and local weather conditions.

Furthermore, it indicates that the atmosphere/weather environment corresponds to the Air - Outdoor, Air - Outdoor (External) (includes salt-laden atmospheric air and salt water spray).

and Air - Indoor and Outdoor environments described in the GALL Report.

SRP-LR, Revision 2, Sections 3.4.2.2.2 and 3.4.2.2.3, address cracking due to stress corrosion cracking (SCC) and loss of material due to pitting and crevice corrosion, respectively, of stainless steel components in the steam and power conversion system. SRP-LR, Revision 2, also states that applicable outdoor air environments (and associated indoor air environments) include, but are not limited to, those within approximately 5 miles of a saltwater coastline, those within 1/2 mile of a highway which is treated with salt in the wintertime, those areas in which the soil contains more than trace chlorides, those plants having cooling towers where the water is treated with chlorine or chlorine compounds, and those areas subject to chloride contamination from other agricultural or industrial sources.

The GALL Report, Revision 2, items VIII.D1.SP-118 and VIII.D1.SP-127, recommend AMP XI.M36, "External Surfaces Monitoring of Mechanical Components," to manage these aging effects. In addition, SRP-LR, Revision 2, states that the GALL Report recommends further evaluation to determine whether an adequate aging management program is used to manage this aging effect based on the environmental conditions applicable to the plant and ASME Code Section XI, requirements applicable to the components.

Issue:

In contrast with the guidance of SRP-LR, Revision 2, and the GALL Report, Revision 2, the LRA does not address the evaluation of environmental conditions in determining whether cracking due to SCC and loss of material due to pitting and crevice corrosion are applicable to the CASS valves. The staff needs the following information to determine the applicability of these aging effects to the CASS valves in the atmosphere/weather environment: (1) evaluation of the site environmental conditions in terms of its effect on occurrence of stress corrosion cracking and pitting and crevice corrosion of these components; and (2) relevant operating experience including the results of applicable ASME Code Section XI inservice inspections.

- 34 Request:

1. For each unit, provide detailed information regarding the system and location of the CASS valves exposed to the atmosphere/weather environment (for example, valves installed on the supply piping from the auxiliary feedwater storage tank).

2. Justify why the atmosphere/weather environment at the site is not conducive to stress corrosion cracking, pitting corrosion and crevice corrosion. In the justification, consider that the facility is close enough to a saltwater coastline so that sufficient halides can be deposited on the components, thereby facilitating stress corrosion cracking and pitting and crevice corrosion.

As part of the response, if the components are covered or protected against direct wetting due to rain, snow and similar weather conditions (for example, by a roof, coating, or protection structure), describe how the components are covered or protected against these environmental conditions.

3. Describe applicant's operating experience related to these CASS valves exposed to the atmosphere/weather environment in terms of the occurrence of stress corrosion cracking, and pitting and crevice corrosion. As part of the response, discuss the results of applicable ASME Code Section XI, inservice inspections and system walk-downs.

4. If the applicant's evaluation of the environmental conditions or operating experience indicates potential for stress corrosion cracking, pitting corrosion or crevice corrosion, propose an aging management program to manage cracking and loss of material of these components.

RAI3.1.2.2.7.2-1

Background:

LRA item 3.1.1-24 and LRA Section 3.1.2.2.7.2 state that, for managing cracking due to stress corrosion cracking of CASS piping components exposed to reactor coolant, the Water Chemistry Program is augmented by the ASME Section Xllnservice Inspection, Subsections IWB, IWC, and IWD Program to ensure that adequate inspection methods are used to detect cracks. LRA Table 3.1.2-2 indicates that these aging management review results by the applicant are consistent with the GALL Report, item IV.C2-3.

By comparison, the GALL Report, item IV.C2-3, recommends the Water Chemistry Program and a plant-specific program to manage cracking due to stress corrosion cracking of Class 1 CASS piping, piping components, and piping elements and that this plant-specific program should include adequate inspection methods to ensure detection of cracks.

Appendix VIII, Supplement 9 of the 2004 edition of the ASME Code Section XI, Division 1 indicates that the qualification requirements for ultrasonic examination of CASS piping welds are in the course of preparation. The "detection of aging effects" program element of the GALL Report, Revision 2, AMP XI.M12, "Thermal Aging Embrittlement of Cast Austenitic Stainless

- 35 Steel (CASS)," addresses inspection methods for CASS components by stating that current ultrasonic testing (UT) methodology cannot detect and size cracks in CASS components; thus, enhanced visual examination (EVT-1) is used until qualified UT methodology for CASS can be established. AMP XI.M12 further states that a description of EVT-1 is found in Boiling Water Reactor Vessel and Internals Project (BWRVIP)-03 (Revision 6) and Materials Reliability Program (MRP)-228 for PWRs.

Issue:

Even though LRA Section 3.1.2.2.7.2 states that the Water Chemistry Program is augmented by the ASME Section XI Inservice Inspection. Subsections IWB. IWC. and IWD Program to ensure adequate inspection methods for detection of cracks. the LRA does not provide the specific inspection methods to be used to ensure the detection of cracks in the CASS piping components.

Request:

Considering that currently there is no qualified UT methodology for the detection of cracks in CASS piping components. describe the inspection methods that will be used to detect cracking due to SCC in the CASS piping components. and justify why these inspection methods are adequate to detect and manage the aging effect.

RAI3.1.2.1-1

Background:

LRA Table 3.1.2-1 for the reactor vessel. reactor vessel internals. and reactor coolant system does not address AMR items consistent with the GALL Report. Revision 2. items IV.B2.RP-265, IV.B2.RP-267, IV.B2.RP-268. and IV.B2.RP-269 for the components'with no additional measures and the aging effects in inaccessible locations.

The GALL Report, Revision 2, item IV.B2.RP-267, addresses loss of fracture toughness due to neutron irradiation embrittlement, changes in dimension due to void swelling. loss of preload due to thermal and irradiation enhanced stress relaxation, and loss of material due to wear of the stainless steel and nickel alloy reactor vessel internal (RVI) components with no additional measures, which are managed by GALL AMP XI.M16A. "PWR Vessel Internals." Similarly. the GALL Report, Revision 2. item IV.B2.RP-265, addresses cracking due to SCC and irradiation-assisted stress corrosion cracking (IASCC) of the stainless steel and nickel alloy RVI components with no additional measures, which are managed by GALL AMPs XI.M2. "Water Chemistry," and XI.M16A, "PWR Vessel Internals".

In addition, the GALL Report, Revision 2, item IV.B2.RP-269. recommends GALL AMP XI.M16A, to manage loss of fracture toughness due to neutron irradiation embrittlement, changes in dimension due to void swelling. loss of preload due to thermal and irradiation enhanced stress relaxation, and loss of material due to wear in inaccessible locations of the stainless steel and nickel alloy RVI components. Similarly, the GALL Report, Revision 2, item IV.B2.RP-268, recommends GALL AMPs XI.M2 and XI.M16A, to manage cracking due to SCC

- 36 and IASee in accessible locations of stainless steel and nickel alloy RVI components. These two AMR items and SRP-LR, Revision 2, Sections 3.1.2.2.9 and 3.1.2.2.10 recommend that if an aging effect is identified in the accessible locations of the components, further evaluation should be performed on a plant-specific basis to ensure that the aging effect is adequately managed in the inaccessible locations.

Issue:

The GALL Report, Revision 2, addresses items IV.B2.RP-267 and IV.B2.RP-265 for the components with no additional measures. MRP-227 addresses the "No Additional Measures" functional group and indicates that the components in this functional group do not require additional measures for aging management as screened in MRP-227, even though these components are included in the scope of the applicant's aging management. In addition, the GALL Report, Revision 2, addresses items IV.B2.RP-269 and IV.B2.RP-268 to ensure adequate aging management for the inaccessible locations of the RVI components in consideration of ag ing effects identified in the accessible locations. By contrast, LRA Table 3.1.2-1 for the reactor vessel, reactor vessel internals, and reactor coolant system does not address AMR items consistent with the GALL Report, Revision 2, items IV.B2.RP-265, IV.B2.RP-267, IV.B2.RP-268, and IV.B2.RP-269 for the components with no additional measures and aging effects in inaccessible locations.

Request:

Provide justification as to why LRA 3.1.2-1 does not address AMR items consistent with the GALL Report, Revision 2, items IV.B2.RP-265, IV.B2.RP-267, IV.B2.RP-268, and IV.B2.RP-269 for the components with no additional measures and aging effects in inaccessible locations. If it cannot be justified, revise the LRA consistent with these AMR items in the GALL Report, Revision 2. In addition, if an aging effect has been identified in accessible locations of the reactor vessel internal components, provide further evaluation to ensure that the aging effect is adequately managed for the inaccessible locations as recommended in the GALL Report, Revision 2, and SRP-LR, Revision 2.

Copper Alloy (075)

RAI 3.3.2.3.10-1

Background:

LRA Tables 3.3.2-10 and 3.3.2-20 include AMR items for copper alloy tubing exposed to ventilation atmosphere (internal) and for copper alloy valves exposed to plant indoor air (internal), respectively. For each of these items, the LRA states that there is no aging effect and no aging management program is recommended. The AMR items cite generic note G, indicating that environment is not in the GALL Report for the component and material combination.

LRA Table 3.0-1, Mechanical Environments, states that "ventilation atmosphere (internal)"

encompasses the GALL Report environments of "air indoor - uncontrolled" and "condensation

- 37 (internal.)" LRA Table 3.0-1 also states that "plant indoor air (when used as internal)"

encompasses the GALL Report environments of "condensation (internal)," "air," and "moist air and condensation."

The GALL Report, item VII.G-9, AP-78, states that copper alloy piping, piping components, and piping elements exposed to condensation (internal) may experience loss of material due to pitting and crevice corrosion and recommends that a plant-specific aging management program be evaluated to manage the aging effect. However, the GALL Report, items VILJ-3, AP-8, and VIII.J-2, SP-6, also state that copper alloy piping, piping components, and piping elements exposed to dry air or uncontrolled indoor air have no aging effects requiring management and that no AMP is recommended.

Issue:

The LRA does not provide sufficient information for the staff to determine whether the copper alloy tubing and valves are exposed to moist or dry air environments; and, therefore, the staff cannot determine whether the applicant has appropriately evaluated all of the credible aging effects for these components.

Reguest:

State the normal environment for the copper alloy tubing exposed to ventilation atmosphere (internal) in LRA Table 3.3.2-10 and for the copper alloy valves exposed to plant indoor air (internal) in LRA Table 3.3.2-20, and provide the basis for the determination that these components have no aging effects requiring management during the period of extended operation.

Elastomers (079)

RAI 3.3.2.3.18-1

Background:

In LRA Table 3.3.2-18, the applicant stated that, for elastomer flexible hoses exposed to a fuel oil internal environment, there is no aging effect and no AMP is proposed. The AMR line items cite generic note G. The GALL Report does not address elastomeric materials exposed to fuel oil.

Issue:

Given that certain elastomers such as natural rubbers and ethylene-propylene-diene (EPDM) are not resistant to fuel oil, the staff needs to know the material of construction of the flexible hoses to determine if there are no aging effects.

- 38 Request:

State the materials of construction for the flexible connections exposed to fuel oil as listed in LRA Tables 3.3.2-18. If the flexible hoses are constructed of a material that is not resistant to fuel oil, propose an aging management program or state the basis for why no aging management program is necessary.

Electrical Insulators-Conductors (080)

RAI3.6-1

Background:

The SRP-LR, Revision 2, states that reduced insulation resistance due to presence of surface contamination could occur in high-voltage insulators. The GALL Report recommends further evaluation of a plant-specific AMP to ensure that this aging effect is adequately managed. The staff noted during the audit that STP experienced a number of instances of flashover events early in plant life due to lime deposits from heavy dust. The large build up of contamination may enable the conductor voltage to track along the surface more easily and can lead to insulator flash over. The applicant conducted frequent wash-downs of insulators to reduce occurrences of flashover. The applicant also uses silicone insulator coatings to eliminate the flashover events and conducts visual inspections during walk downs to ensure the effectiveness of the silicon coatings. However, the applicant stated in the STP LRA that surface contamination is not an applicable aging effect requiring management for high-voltage insulators at STP.

Issue:

Surface contamination could be a potential aging effect of high-voltage insulators. Reduced insulator resistance due to the presence of surface contamination may enable the conductor voltage to track along the surface more easily and can lead to insulator flash-over.

Request:

Explain why walk down activities to inspect the high-voltage insulator silicon coatings are not considered aging management of insulators. In addition, explain why the high-voltage insulator silicone coating will remain effective for the period of extended operation and why an aging management program is not needed.

- 39 Heat Exchangers (085)

RAI 3.3.2.2.4-1

Background:

The acceptance criterion in SRP-LR Section 3.3.2.2.4, item 1, states that cracking due to SCC is managed by monitoring and controlling primary water chemistry, but states that the effectiveness of water chemistry control programs should be verified, because water chemistry controls do not preclude cracking due to SCC and cyclic loading. The GALL Report recommends that a plant-specific AMP be evaluated to ensure these aging effects are adequately managed, and that an acceptable verification program includes temperature and radioactivity monitoring of the shell side water and eddy current testing of tubes. LRA Section 3.3.2.2.4, item 1, states that cracking due to SCC and cyclic loading in stainless steel non regenerative heat exchanger components is managed by the Water Chemistry Program, and that the effectiveness of the Water Chemistry Program will be confirmed by the One-Time Inspection Program, which includes selected components at susceptible locations. The LRA states that the One-Tme Inspection Program was selected in lieu of eddy-current testing of tubes to confirm that cracking is not occurring.

Issue:

LRA Section B2.1.16, "One-Time Inspection," states that selecting piping and components within the material-environment groups for inspection is based on criteria provided in the one-time inspection procedure. However, it is not clear whether the non-regenerative heat exchangers will be included in the sample of components to be inspected; and, since eddy current testing is not used, what inspection techniques will be used.

Request:

(1) Clarify if the non-regenerative heat exchangers will be included in the sample of components to be inspected by the One-Time Inspection Program.

(2) Provide technical justification for not using eddy current testing to confirm that cracking is not occurring in heat exchanger tubes. Provide details on the alternate inspection technique that will detect cracking in the heat exchanger tubes to verify the effectiveness of Water Chemistry Program.

RAJ 3.4.2.2.4-1

Background:

SRP-LR 3.4.2.2.4, item 1, is associated with LRA Table 3.4.1, item 3.4.1.9, and addresses stainless steel and copper heat exchanger tubes exposed to treated water which will be managed for reduction of heat transfer due to fouling by the Water Chemistry and One-Time Inspection programs. The applicant addressed the further evaluation criteria of the SRP-LR by

- 40 stating that the Water Chemistry and One-Time Inspection programs manage loss of heat transfer due to fouling for copper alloy components exposed to secondary water.

Issue:

In its review of components associated with item 3.4.1-9, the staff noted that LRA Table 3.4.2-6 addresses stainless steel heat exchangers (AF turbine oil cooler) in secondary water environment, which will be managed by the Water Chemistry and One Time Inspection programs for reduction of heat transfer due to fouling; however, the staff did not find any AMR line items for copper alloy heat exchangers.

Request:

Clarify that LRA Section 3.4.2.2.4.1 applies to stainless steel heat exchangers and confirm if there are copper alloy heat exchangers in treated water environment with an aging effect of reduction of heat transfer in steam and power conversion systems.

RAI 3.4.2.2.4-2

Background:

SRP-LR 3.4.2.2.4, item 2, is associated with LRA Table 3.4.1, item 3.4.1.10, and addresses steel, stainless steel, and copper heat exchanger tubes exposed to lubricating oil which will be managed by the Lubricating Oil Analysis and One-Time Inspection programs for reduction of heat transfer due to fouling. The applicant addressed the further evaluation criteria of the SRP-LR by stating that the Lubricating Oil Analysis and One-Time Inspection programs manage loss of heat transfer due to fouling for copper alloy components exposed to lubricating oil.

Issue:

In its review of components associated with item 3.4.1-10, the staff noted that LRA Table 3.3.2-9 addresses stainless steel heat exchangers (lube oil cooler), and LRA Table 3.4.2-6 addresses stainless steel heat exchangers (AF turbine oil cooler) in lubricating oil environment, which will be managed by the Lubricating Oil Analysis and One Time Inspection programs for reduction of heat transfer due to fouling; however, the staff did not find any AMR line items for copper alloy heat exchangers.

Request:

Clarify that LRA Section 3.4.2.2.4.2 applies to the above stainless steel heat exchangers, and confirm if there are copper alloy heat exchangers in a lubricating oil environment with an aging effect of reduction of heat transfer in steam and power conversion systems.

- 41 RAI 3.3.2.4-1

Background:

SRP-LR Table 2.1-3 states that both the pressure boundary and heat transfer functions for heat exchangers should be considered because heat transfer may be a primary safety function of these components. The staff noted that it provided this clarification of the SRP-LR to the industry by letter dated November 19, 1999. In addition, the GALL Report,Section IX.F, "Aging Mechanisms," states that fouling can be categorized as particulate fouling from dust. and that fouling can result in a reduction of heat transfer.

Issue:

In its review of heat exchanger-related AMR line items, the staff noted that the LRA listed multiple components in multiple systems with an intended function of heat transfer, but did not include reduction of heat transfer as an aging affect requiring management for these components. The LRA was not consistent, in that some of the above noted heat exchangers in treated borated water and closed cooling water environments are being managed for reduction of heat transfer whereas others are not. In addition, heat exchangers with an intended function of heat transfer in various air environments are not being managed for reduction of heat transfer, which may be adversely affected by fouling due to dust.

Reguest:

For those heat exchanger-related line items in the LRA that list an intended function of heat transfer, but do not consider reduction of heat transfer as an aging effect requiring management, provide the technical bases demonstrating that reduction of heat transfer does not need to be managed for each of these components.

Structures (087)

RAI 3.5.2.2.1-1

Background:

SRP-LR Section 3.5.2.2.1.4 addresses loss of material due to general, pitting and crevice corrosion for steel elements of accessible and inaccessible areas of containments. The GALL Report recommends further evaluation if the following four the GALL Report, item II.A 1-11 conditions cannot be satisfied:

(1) Concrete meeting the specifications of ACI 318 or 349 and the guidance of ACI 201.2R was used for the containment concrete in contact with the embedded containment shell or liner.

(2) The concrete is monitored to ensure that it is free of penetrating cracks that provide a path for water seepage to the surface of the containment shell or liner.

-42 (3) The moisture barrier, at the junction where the shell or liner becomes embedded, is subject to aging management activities in accordance with ASME Code Section XI, Subsection IWE requirements.

(4) Water ponding on the containment concrete floor is not common, and is cleaned up in a timely manner when detected.

In addition, several other SRP-LR sections (e.g. 3.5.2.2.1.10 and 3.5.2.2.2.2.2) state that further evaluation is unnecessary if the concrete was constructed in accordance with ACI 318 or the recommendations of ACI 201.2R.

Issue:

The staff agrees that conditions (2), (3), and (4) were addressed adequately by the applicant; however, the LRA did not specify that condition (1) was met. The LRA stated that concrete structures were designed and constructed in accordance with ACI and ASTM standards and that concrete mixes were designed in accordance with ACI 211.1. However, the LRA did not clearly explain how the referenced standards compared to ACI 318 and ACI 201.2R.

Request:

Explain how the ACI and ASTM standards referenced in the LRA meet the intent of ACI 201.2R or ACI 318. The response should cover containment concrete in contact with the embedded steel liner and all other concrete within the scope of license renewal.

RAI 3.5.2.3.11-1

Background:

For stainless steel exposed to water, the GALL Report lists cracking due to SCC as a possible aging effect and recommends appropriate aging management techniques, as summarized in GALL AMP XI.M32, "One-Time Inspection."

Issue:

LRA Table 3.5.2-11 lists stainless steel supports in a submerged environment and does not include cracking as an applicable aging effect.

Request:

Justify why cracking is not an applicable aging effect for submerged stainless steel supports or include an appropriate AMP to manage cracking in submerged stainless steel supports. If an AMP is credited with managing this aging effect, provide a technical justification for the credited aging management technique (i.e. inspection method, frequency, etc.).

- 43 Non-Metallic (092)

RAI 3.1.2.3.2-1

Background:

LRA Tables 3.1.2-2, 3.2.2-3, 3.3.2-19, 3.4.2-1, 3.4.2-3, and 3.4.2-5 include items for fiberglass and calcium silicate insulation exposed to plant indoor air. The applicant stated that there are no aging effects for these material-environment combinations requiring aging management, and that no aging management program is proposed. In LRA Section 2.1.4.1 t the applicant stated that for systems where it has an intended function, insulation was considered within the scope of license renewal and subject to AMR, and is included as a component type in each appropriate in-scope system. The applicant also stated that insulation has an intended function of "insulate," which is defined in Table 2.1-1 as controlling heat loss. UFSAR Section 5.2.3.2.3 states that "The thermal insulation used on the reactor coolant pressure boundary is either reflective stainless steel type or made of compounded materials which yield low leachable chloride and/or fluoride concentrations."

Issue:

The staff notes that in a dry environment of indoor or outdoor air, without potential for water leakage, spray, or condensation, fiberglass and calcium silicate are expected to be inert to environmental effects. However, in moist environments, calcium silicate has been found to degrade. In addition, both fiberglass and calcium silicate insulation have the potential for prolonged retention of any moisture to which they are exposed; prolonged retention of moisture may increase thermal conductivity, thereby degrading the insulating characteristics, and could accelerate the aging of insulated components. The staff noted that for each of the above tables, there is an item for either aluminum or stainless steel material with an insulation function and exposed to the plant indoor air environment. It would appear that these items are jacketing for the insulation; however, it is not clear to the staff all in-scope insulation is protected by jacketing materials or how the insulation is installed such that water intrusion is prevented.

Reguest:

For LRA Tables 3.1.2-2, 3.2.2-3, 3.3.2-19, 3.4.2-1, 3.4.2-3, and 3.4.2-5, state whether all of the fiberglass or calcium silicate insulation is covered by jacketing, and what procedure requirements are in place so as to prevent water intrusion into the insulation (e.g., seams on the bottom, overlapping seams) such that aging management is not required.

RAI 3.3.2.3.19-1

Background:

In LRA Table 3.3.2-19, the applicant stated that, for a thermoplastic tank exposed to plant indoor air, there is no aging effect and no AMP is proposed.

- 44 Issue:

The staff could not confirm that no credible aging effects are applicable for this component, material, and environment combination because there are many material types called "thermoplastics," with variable aging effects when exposed to environments such as ultraviolet light, high radiation, ozone, or chemical species.

Request:

State the specific material of construction for the thermoplastic tank listed in LRA Table 3.3.2-19. State whether there are external environmental factors in the vicinity of the component, such as ultraviolet light, high radiation, temperature, ozone, or chemical species. If these factors could contribute to aging, state the aging effect and the basis for not managing the aging. Alternatively, if external environmental factors could contribute to aging, propose an aging management program to manage the aging effect.

RAI 3.3.2.3.24-1

Background:

LRA Table 3.3.2-24 includes an item for PVC piping exposed to raw water. In the LRA, the applicant states that there are no aging effects for this material and environment combination requiring aging management and no aging management program is proposed. The staff noted that PVC piping exposed to raw water is not addressed in the GALL Report. LRA Table 3.0-1, Mechanical Environments, states that, "Floor drains and building sumps may be exposed to a variety of untreated water that is classified as raw water for the determination of aging effects.

Raw water may contain contaminants, including oil and boric acid, as well as originally treated water that is not monitored by a chemistry program."

Issue:

Based on current industry research and operating experience related to PVC piping and piping components, the staff has determined that the factors related to passive aging that may contribute to the degradation of thermoplastics (e.g., PVC, PVDF) include chemical degradation through hydrolysis, and oxidation reactions with a solvent. The staff noted that the raw water environment in the floor drains could include contaminants such as oil and boric acid, which could have a deleterious effect on thermoplastics from a chemical or oxidation reaction.

Request:

State the specific type of PVC piping exposed to raw water in LRA Table 3.3.2-24. State whether this piping could be exposed to contaminants such as oil and boric acid, or other environmental factors that could result in aging effects. State the basis for why there are no aging effects needing management based on the environmental factors for which the piping is exposed, or provide an aging management program to adequately manage the aging effect.

- 45 Plant Indoor Air (098A)

RAI3.0-1

Background:

LRA Table 3.0-1 states that the plant indoor air environment encompasses the GALL Report defined environments of "air-indoor controlled," "air-indoor uncontrolled," "condensation," "air, moist," and "air with steam or water leakage."

Issue:

The staff identified a number of Table 2 items for which there are no specified aging effects when exposed to "air-indoor controlled." However. the staff also identified that these same Table 2 items would have aging effects if they were exposed to "air-indoor uncontrolled,"

"condensation," "air. moist," or "air with steam or water leakage." as defined by the GALL Report. It is unclear to the staff if the components with an environment of plant indoor air are exposed to these potentially adverse environments. Without this information, the staff cannot evaluate whether the proper aging effects and aging management programs are being applied to manage components for which the environment is listed as plant indoor air.

Reguest:

Identify which AMR items in the LRA are exposed to a plant indoor air environment for which humidity, condensation, moisture, or contaminants are present. If in identifying these items it is determined that there are aging effects requiring management. propose an AMP to manage the aging effect or state the basis for why no AMP is required.

Stainless Steel (0988)

RAJ 3.5.1.59-1

Background:

GALL AMP XI.S3. "ASME Section XI. Subsection IWF," covers the inspection criteria for ASME Code Class 1, 2, and 3 component supports for license renewal and recommends visual inspection of a sample of supports.

LRA Table 3.5.2-11 includes AMR items for stainless steel ASME Class 1. 2. and 3 supports exposed to borated water leakage and plant indoor air which have no AERM assigned and no AMP proposed. The AMR items reference LRA Table 3.5.1, item 3.5.1-59. However. the staff has identified that these supports appear to be within the scope of ASME Code Section XI.

Subsection IWF.

- 46 Issue:

The staff has identified examples of ASME Class 1,2, and 3 supports in LRA Table 3.5.2-11 that appear to be within the scope of ASME Code Section XI, Subsection IWF; but have been inappropriately identified as having no AERM. As a result, the ASME-required inspections of these supports may not be performed.

Request:

Identify whether there are any ASME Class 1, 2, or 3 supports within the scope of license renewal which are not being managed by the ASME Code Section XI, Subsection IWF Program.

Provide justification for why the supports are not being managed using the ASME Code Section XI, Subsection IWF Program; or provide an appropriate program to manage the aging effects.

Stainless Steel (Og8e)

RAI 3.3.2.3.17-1

Background:

LRA Tables 3.3.2-17,3.3.2-27, 3.4.2-4, and 3.4.2-6 include AMR line items for stainless steel components (closure bolting, hatch, piping, tank, tubing, valve) exposed to outdoor air (atmosphere/weather) which state that there are no aging effects and no aging management program is recommended. Most of these items cite generic note G, indicating that the environment is not in the GALL Report for the component and material combination.

The GALL Report, Revision 2, and the SRP-LR, Revision 2, state that under some environmental conditions (e.g., exposure to halides and condensation) cracking due to stress corrosion cracking and loss of material due to pitting and crevice corrosion could occur in stainless steel components exposed to outdoor air. The GALL Report and the SRP-LR also recommend that an evaluation be performed based on plant environmental conditions to determine whether aging effects need to be managed for this material and environment combination.

Issue:

The staff noted that for some specific AMR line items (Le., LRA Table 3.4.2-6, item referring to plant-specific note 3) an evaluation of environmental conditions appears to have been performed. However, it is not clear to the staff that this evaluation has been performed for all in scope stainless steel components exposed to outdoor air (atmosphere/weather) for which no aging effects are identified.

Request:

Provide an evaluation based on environmental conditions as recommended in the GALL Report, Revision 2, and the SRP-LR, Revision 2, to document the basis for concluding that stainless steel components exposed to outdoor air (atmosphere/weather) have no aging effects requiring

- 47 management or provide an appropriate program to manage loss of material and cracking for these components.

Steel-Other (100)

RAI 3.3.1.92-01

Background:

LRA Table 3.3.2-17 includes an AMR item for a galvanized carbon steel damper exposed to ventilation atmosphere (internal) in the fire protection system. The AMR item is linked to LRA Table 3.3.1, item 3.3.1-92 (galvanized steel piping exposed to uncontrolled indoor air), which states that there is no aging effect requiring management and no AMP is recommended.

The staff noted that there are similar AMR items for galvanized carbon steel dampers in LRA Tables 3.3.2-10,3.3.2-11,3.3.2-12,3.3.2-14, and 3.3.2-15. For these similar items with similar environments to those listed in Table 3.3.2-17, the LRA states that loss of material is a potential aging effect and the aging effect is managed by the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program. These items are associated with Table 3.3.1, item 3.3.1-72 (steel ducting components exposed to condensation).

The LRA definition of ventilation atmosphere includes condensation and condensation with surface contaminants.

Issue:

It is not clear to the staff why the galvanized carbon steel damper in LRA Table 3.3.2-17 is managed differently than AMR items in Tables 3.3.2-10,3.3.2-11,3.3.2-12,3.3.2-14, and 3.3.2-15 with identical component, material, and environment combinations.

The LRA does not provide sufficient information for the staff to determine whether the galvanized carbon steel damper is exposed to a moist or dry air environment; therefore, the staff cannot determine whether the applicant has appropriately evaluated all of the credible aging effects for this component.

Reguest:

For the galvanized carbon steel damper exposed to ventilation atmosphere (internal) in LRA Table 3.3.2-17, provide the basis for the determination that this component has no aging effects requiring management during the period of extended operation.

- 48 RAI 3.3.1.96-1

Background:

Updated staff guidance in SRP-LR, Revision 2, Table 3.3-1, item 112 (the GALL Report, Revision 2, item VII.J.AP-282) recommends that steel piping, piping components, and piping elements exposed to concrete do not need to be age-managed, provided that plant operating experience indicates no degradation of the concrete. If this condition is not met, the SRP-LR recommends that a further evaluation be performed to determine whether aging management of steel components embedded in concrete is needed.

The LRA includes carbon steel and galvanized carbon steel components encased in concrete that do not reflect the updated staff guidance in Revision 2 of the SRP-LR. These items are associated with LRA Table 3.3.1, item 3.3.1-96 (SRP-LR, Revision 1, Table 3.3-1, item 96) and state that there are no aging effects requiring management, and that there is no recommended aging management program.

Issue:

The staff needs additional information to complete its evaluation of carbon steel and galvanized carbon steel components encased in concrete to determine whether there has been any concrete degradation that may have exposed steel components to water and thus have subjected the components to corrosion. Affected systems include, but are not limited to, the electrical auxiliary building and control room HVAC system, radioactive vents and drains system, and containments, structures, and component supports system.

Request:

For carbon steel and galvanized carbon steel components encased in concrete, state whether there has been any degradation of concrete in the vicinity of the embedded components such that the components would be exposed to water and thus be subject to corrosion. If such concrete degradation has occurred, state what further evaluation has or will be performed to determine whether aging management of steel components embedded in concrete is needed, consistent with the updated guidance in Revision 2 of both the SRP-LR and the GALL Report. If aging management of these components is needed, propose an appropriate aging management program. If aging management is not needed, provide an appropriate justification.

Stress-Corrosion cracking (101)

RAI 3.1.2.2.16.1-1

Background:

The GALL Report, item IV.A2-11, recommends AMP XI.M2, "Water Chemistry," and AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWO" to manage cracking due to SCC and primary water stress corrosion cracking (PWSCC) of stainless steel and nickel alloy control rod drive head penetration pressure housing. Examination Category B

- 49 0, Item No. B14.20 in Table IWB-2500-1 of the ASME Code Section XI, 2004 edition with no addenda states that volumetric or surface examinations shall be applied for welds in control rod drive (CRD) housings.

LRA Table 3.1.1, item 3.1.1-34 addresses cracking due to SCC and PWSCC of stainless steel and nickel alloy reactor control rod drive head penetration pressure housing, which are managed by the Water Chemistry Program (LRA Section B2.1.2) and Inservice Inspection Program (LRA Section B2.1.1). LRA item 3.1.1-34 states that this aging effect's further evaluation is addressed in LRA Section 3.1.2.2.16.1, "Cracking due to Stress Corrosion Cracking and Primary Water Stress Corrosion Cracking."

LRA Section 3.1.2.2.16.1 states that. for managing cracking due to SCC for stainless steel components exposed to reactor coolant, the Water Chemistry Program (LRA Section B2.1.2) is augmented by the ASME Code Section Xllnservice Inspection, Subsection IWB, IWC and IWD Program (LRA Section B2.1.1). LRA Section B2.1.1 states that the applicant's ASME Code Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program is consistent with ASME Code Section XI 2004 Edition with no addenda.

Specifically, LRA Table 3.1.2-1 states that following stainless steel components are subject to LRA item 3.1.1-34 and LRA Section 3.1.2.2.16.1: (1) reactor vessel (RV) control rod drive mechanism (CRDM) housing; (2) RV exit thermocouple penetration housing; (3) RV internal disconnect device housing; (4) reactor vessel water level indication system (RVWLlS) upper probe housing; (5) RV CRDM head penetrations (flange and plug); and (6) RV CRDM head penetrations (thermal sleeve).

Issue:

LRA Section B2.1.1 does not address what inspection methods and examination categories are used to manage cracking due to SCC of the following stainless steel components: (1) RVexit thermocouple penetration housing; (2) RV internal disconnect device housing; (3) reactor vessel water level indication system (RVWLlS) upper probe housing; (4) RV CRDM head penetrations (flange and plug); and (5) RV CRDM head penetrations (thermal sleeve). In addition, LRA Section 3.1.2.2.16.1 does not include the RV CRDM housing in the description of the components managed for cracking due to SCC and PWSCC.

Request:

1. Revise LRA Section 3.1.2.2.16.1 in order to include the RV CRDM housing in the LRA section consistent with LRA item 3.1.1-34.

2. Describe the inspection methods and examination categories that the applicant's ASME Code Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program will use to manage cracking due to SCC of the following stainless steel components: (1) RVexit thermocouple penetration housing, (2) RV internal disconnect device housing, (3) reactor vessel water level indication system (RVWLlS) upper probe housing, (4) RV CRDM head penetrations (flange and plug), and (5) RV CRDM head penetrations (thermal sleeve).

- 50 In addition, provide justification as to why the inspection methods are adequate to manage cracking due to SCC of these components.

As part of the response, describe how the plug of the "RV CRDM head penetrations (flange and plug)" component is installed (for example, welded or threaded connection to the penetration flange) in order to clarify whether or not the plug is attached directly to the reactor vessel head as a result of the repair of the CRDM penetration nozzles and to determine the adequacy of the inspection methods for this component.

RAt 3.1.2.2.16.1-2

Background:

The GALL Report, Revision 2, item IV.D1.RP-385, states that GALL AMP XI.M2, "Water Chemistry," manages cracking due to PWSCC of steam generator tube-to-tubesheet welds made of nickel alloy. The GALL Report, item IV.D1.RP-385, also states that a plant-specific program is evaluated to confirm the effectiveness the water chemistry program and to ensure that cracking is not occurring.

SRP-LR, Revision 2, Section 3.1.2.2.11, item 2, states that cracking due to PWSCC could occur in steam generator nickel alloy tube-to-tubesheet welds exposed to reactor coolant and that, unless an NRC-approved pressure boundary definition excludes the tube-to-tubesheet weld, the effectiveness of the primary water chemistry program should be verified to ensure that cracking is not occurring.

LRA Section 3.1.2.2.16.1, "Steam Generator Heads, Tubesheets, and Welds Made or Clad with Stainless Steel," and LRA item 3.1.1-35 state that the applicant has recirculating steam generators, not once-through steam generators, so cracking due to stress corrosion cracking and primary water stress corrosion cracking is not applicable. The applicant's AMR items for the steam generator components, which are described in LRA Table 3.1.2-4, do not address how the applicant manages cracking due to PWSCC of steam generator tube-to-tubesheet welds exposed to reactor coolant.

LRA Section B2.1.8 states that the STP steam generators were replaced with Westinghouse Delta 94 steam generators in 2000 and 2002 for Units 1 and 2, respectively. LRA Section B2.1.8 also states that the STP replacement steam generators are equipped with Alloy 690n tubes.

Issue:

The LRA omits aging management consistent with the GALL Report, Revision 2, item IV.D1.RP-385, to manage cracking due to PWSCC of steam generator tube-to-tubesheet welds made of nickel alloy.

- 51 Request:

Describe the materials that were used for the fabrication of the steam generator tubesheet cladding and the tube-to-tubesheet welds.

1. Describe how cracking due to PWSCC of the steam generator nickel alloy tube-to-tubesheet welds will be managed for the period of extended operation. If the applicant proposes a one-time inspection to manage cracking due to PWSCC of these components, describe the plant-specific operating experience in terms of the occurrence of PWSCC of the tube-to-tubesheet welds.

In addition, if the operating experience indicates that the components have experienced cracking due to PWSCC, justify why the proposed use of a one-time inspection rather than periodic inspections is adequate to manage the aging effect.

2. If the applicant has determined that the materials used for the fabrication of the steam generator tubes, tubesheet cladding and tube-to-tubesheet welds are not susceptible to cracking due to PWSCC, (1) provide the technical basis for the determination and (2) describe how the applicant will evaluate future industry and plant-specific operating experience regarding the PWSCC of the tube-to-tubesheet welds in order to identify and conduct necessary corrective actions for these components.

3. Revise the LRA consistent with the applicant's response, including LRA item 3.1.1-35 and Section 3.1.2.2.16.1.

RAI 3.5.2.2.1.7-1

Background:

The GALL Report, item ILA3-2. states that the containment penetration sleeves and bellows, made of stainless steel and dissimilar metal welds, are subject to cracking due to stress corrosion cracking in the air-indoor uncontrolled or air-outdoor environment. The GALL Report states that the aging effect of these components is managed by GALL AMPs XLS1, "ASME Section XI, Subsection IWE" and XLS4, "10 CFR Part 50, Appendix J." In addition, the GALL Report states that further evaluation should be performed to evaluate the detection of aging effects.

LRA Section 3.5.2.2.1.7, "Cracking due to SCC," which is associated with LRA Table 3.5.1, item 3.5.1-10, addresses cracking due to SCC in stainless steel penetration sleeves, penetration bellows, and dissimilar metal welds. LRA Section 3.5.2.2.1.7 also states that for LRA item 3.5.1-10, cracking due to SCC is not an aging effect requiring management for STP stainless steel containment penetration sleeves, bellows, and dissimilar metal welds. The applicant further stated that both high temperature (> 140°F) and exposure to an aggressive environment are required for SCC to be applicable and at STP, these two conditions are not simultaneously present for any stainless steel penetration sleeves, bellows. or dissimilar metal welds. In addition, the applicant stated that review of STP plant-specific operating experience did not identify any stress corrosion cracking of these components.

- 52 In comparison, LRA Table 3.5.2-1 addresses the applicant's aging management for containments, structures, and component supports. LRA Table 3.5.2-1 indicates that stainless steel containment penetrations and bellows are exposed to plant indoor air and are subject to cracking due to stress corrosion cracking. LRA Table 3.5.2-1 and LRA Table 3.5-1, item 3.5.1-10, indicate that the applicant credited the ASME Code Section XI, Subsection IWE Program and 10 CFR 50, Appendix J Program to manage this aging effect.

During a walk-down for the structures and associated components conducted as part of the aging management program audit, the staff noted the applicant has operating experience with groundwater in-leakage and accumulation in the area between the fuel handling building and the containment building of both Units. The staff noted that this environmental condition can contribute to the occurrence of stress corrosion cracking of these components.

Issue:

The staff noted that the applicant's aging management review results described in LRA Tables 3.5-1 and 3.5.2-1 are in conflict with the applicant's claim described in LRA Section 3.5.2.2.1.7 that cracking due to stress corrosion cracking is not applicable for the stainless steel containment penetration components (sleeves, bellows and dissimilar metal welds). The staff further noted that the LRA does not provide the applicant's evaluation of the operating experience regarding potential exposure of the penetration components to groundwater in-leakage and accumulation even though currently the containment structures are experiencing groundwater in-leakage and accumulation.

In addition, the AMR items for the containment penetration components in LRA Table 3.5.2-1 do not include dissimilar metal welds in the material description columns.

Request:

1. Describe the plant-specific operating experience with groundwater in-leakage and accumulation in order to clarify whether or not the containment penetration components have been exposed to the groundwater. If the containment penetration components have been in contact with the leaked groundwater, justify why the exposure of the components to the groundwater is not conducive to stress corrosion cracking of the stainless steel components, taking into account the potential for the contamination of the leaked groundwater with corrosive species (such as chlorides).

2. Resolve the conflict between the aging management review (AMR) results in LRA Section 3.5.2.2.1.7 and the AMR results in LRA Tables 3.5-1 and 3.5.2-1 in order to clarify whether or not cracking due to stress corrosion cracking is applicable to the stainless steel penetration components. In addition, provide a technical basis for the applicant's determination on the applicability of stress corrosion cracking to the these components.

3. If cracking due to stress corrosion cracking is applicable to the containment penetration components, justify why the use of the AMSE Code Section XI, Subsection IWE Program and the 10 Part 50, Appendix J Program, without the additional augmented inspection recommended in the GALL Report, is adequate to detect and manage the aging effect.

- 53

4. Describe how the applicant will evaluate the future operating experience to identify and perform any necessary corrective action for ensuring that the intended functions of these components are maintained. As part of the response, clarify whether or not the applicant's evaluation of future operating experience will include the inspection and test results of the AMSE Code Section XI, Subsection IWE Program and the 10 Part 50, Appendix J Program.

5. Justify why dissimilar metal welds are not included in the material description columns of the AMR items for the containment penetration components in LRA Table 3.5.2-1. In addition, revise the LRA consistent with the applicant's response.

SOUTH TEXAS PROJECT, UNITS 1 AND 2 REQUEST FOR ADDITIONAL INFORMATION AGING MANAGEMENT REVIEW, SET 1 (TAC NOS. ME4936 AND ME4937)

Identification of Time-Limited Aging Analyses (TLAAs) (058)

RAI4.1-2 (Absence ofTLAA for the Containment Liner Plates)

Background:

License renewal application (LRA) Section 4.6 states that the applicant's review of the current licensing basis (CLB) did not identify any fatigue analyses for the containment liner plates or containment equipment hatches. LRA Section 4.6 states that the original specification for procurement of the containment liner indicated that fatigue was to be evaluated per NE-3222.4 and NE-3131 (d) of the American Society of Mechanical Engineers (ASME) Code Section III, and that the 1974 Edition of ASME Code Section III, Division 1, Subsection NE. subparagraph NE-3222.4. provides the rules for performing fatigue analyses of metal containment (MC) components, which includes subparagraph NE-3222.4(d) provisions on when a given MC component could be waived from the mandated fatigue analysis requirements.

LRA Section 4.6 also states that the containment liners were designed in accordance with the specifications in Bechtel Specification BC-TOP-1 and the design requirements in the 1973 Edition of ASME Code Section III. Division 2, inclusive of Addenda 1 through 6 of the Code.

The staff also noted that the applicant indicated that its search of CLB documents did not identify any fatigue analyses of record for the South Texas Project (STP) metal containment liners.

Issue:

There is an inconsistency or gap in the information provided in LRA Section 4.6 concerning the design requirements for the containment liners. In one part of the section, the applicant indicates that the containment liners were designed, procured, and installed to Bechtel Specification BC-TOP-1 specifications and to the 1973 ASME Code Section III requirements.

However, in another part of this LRA section, the applicant indicates that the liners were to be procured to the requirements in the 1974 Edition of ASME Code Section III, including the fatigue analysis requirements in ASME Code Section III, subparagraph NE-3222.4. In addition, the applicant does not make any statement or provide any discussions on whether a fatigue exemption (waiver) analysis had been performed for the containment liners under the provisions of ASME Code Section III, subparagraph NE-3222.4(d). In addition, STP UFSAR Section 3.8.1.5.9 states that the cyclic stresses and strains in the containment liners are considered in performing a fatigue analysis. Thus the staff has difficulty in understanding why the containment liners would not have been designed and procured to the requirements in the 1974 edition of ASME Code Section III, as stated in the LRA, or why appropriate fatigue analyses would not have been required for these liners under the requirements of the 1974 Edition of the ASME Code Section III, Subparagraph NE-3222.4.

ENCLOSURE 2

- 2 Request:

Clarify which edition of the ASME Code Section III, Subarticle NE-3000 was used for the design of the containment liner, and if the 1973 edition is the appropriate ASME Code Section code of record, explain why subparagraph NE-3222.4 in the 1974 Edition of the code would not have been applied to containment liners when the owner's procurement specification would have called for its use. Consistent with this response, justify why an NE 3222.4 subparagraph-required fatigue analysis was not performed for the containment liners under the appropriate ASME Code Section III, design rules. With respect to this response, clarify whether the containment liners had been exempted (waived) from a fatigue analysis under provisions of NE-3222.4(d), and if so, justify why the fatigue waiver analysis would not need to be identified as a TLAA for the LRA when compared to the fatigue waiver analysis for the personnel and emergency (auxiliary) air locks, which was identified as a TLAA for the application.

RAI4.1-3 (Absence ofTLAA for RPV Underclad Cracking)

Background:

LRA Table 4.1-2 and LRA Section 4.7.4 state that the applicant's review of the CLB did not identify any time dependent flaw growth, flaw tolerance, or fracture mechanics evaluations in assessment of reactor pressure vessel (RPV) underclad cracks. The applicant states that, although there is an applicable Westinghouse Topical Report that assesses fatigue flaw growth analysis in RPV underclad cracks, the report is not being applied as part of STP CLB for managing the potential for underclad cracks to in the welds that are used to join the cladding to the RPV forging components that are made from SA-50B, Class 2 materials. The applicant stated that instead, its design basis uses the application of Regulatory Guide (RG) 1.43, "Control of Stainless Steel Weld Cladding of Low-Alloy Steel Component" [May 1973], as the basis for precluding or mitigating the occurrence of underclad cracks in the SA 50B RPV forging-to-cladding welds.

The staff verified in STP Updated Final Safety Analysis Report (UFSAR) Section 5.2.3.3.2, that the applicant is crediting the basis in RG 1.43. This UFSAR section states that all welding at STP is conducted utilizing procedures that are qualified in accordance with the applicable weld qualification rules of the ASME Code Sections III and IX, and that control of welding variables, as well as examination and testing during procedure qualification and production welding, is performed in accordance with the applicable ASME Code requirements. UFSAR Section 5.2.3.3.2 also states that Westinghouse (as the NSSS vendor of the STP RPV) meets the intent of RG 1.43 by requiring qualification of any high-heat input welding process (e.g.,

submerged-arc wide-strip welding process or a submerged-arc-6-wire welding process) used on SA-50B Class 2 material, with a performance test as described in regulatory position 2 of the RG 1.43. However, another section of the UFSAR (i.e. UFSAR Section 5.3.1.2) indicates that the referenced procedure qualification was to be accompanied with a special evaluation in order to assure freedom from the underclad cracking phenomenon.

- 3 Issue:

LRA Section 4.7.4 only refers to the use of RG 1.43 and the applicability of the information in UFSAR Section 5.2.3.3.2. LRA Section 4.7.4 does not make any reference to the "special evaluation" that is referenced in UFSAR Section 5.3.1.2 for the evaluation of RPV underclad cracking. In order to understand the complete basis described in LRA Section 4.7.4, the staff needs clarification regarding what was done in the CLB or current design basis to satisfy the STP UFSAR Section 5.3.1.2 protocol for performing the special evaluation mentioned in the UFSAR section. If such a "special evaluation" was implemented as part of the CLB or design basis, the basis in LRA Section 4.7.4 should also assess how the "special evaluation" compares to the six criteria for TLAAs in 10 CFR 54.3, and justify whether it needs to be identified as a TLAA for the LRA under the requirements of 10 CFR 54.21(c)(1).

Request:

Discuss and clarify how the applicant fulfilled the STP UFSAR Section 5.3.1.2 protocol for performing the "special evaluation" mentioned in the UFSAR section, and summarize what the special evaluation involved, along with an appropriate CLB or design basis reference. If such a "special evaluation" was implemented as part of the CLB or design basis, clarify how the "special evaluation" compares to the six criteria for TLAAs in 10 CFR 54.3, and justify whether or not the "special evaluation" should be identified as a TLAA for the LRA under the TLAA identification requirements of 10 CFR 54.21(c)(1). Otherwise, if the "special evaluation" was not implemented as part of the CLB or current design basis, clarify how conformance with RG 1.43 was accomplished in the design basis without the implementation of the "special evaluation" and justify why the "special evaluation" would not need to be implemented as part of the design basis in order to demonstrate conformance with the regulatory position in RG 1.43 (i.e., contrary to the design basis statement that is currently given in UFSAR Section 5.3.1.2) and that underclad delaminations (i.e., underclad cracking) in the RPV SA-50B forging-to-cladding welds would be adequately prevented or mitigated as an applicable aging effect and mechanism during the period of extended operation using the RG 1.43 conformance basis.

RAI 4.1-4 (Absence of TLAA for the Turbine-Driven AFW Pump Supply Piping)

Background:

LRA Table 4.1-2 identifies that the applicant's review of the CLB did not identify any time-dependent fatigue analyses for the main steam supply lines to the turbine-driven auxiliary feedwater (AFW) pumps. Therefore, the applicant states that LRA does not need to include a fatigue TLAA for these lines because the generic "fatigue analysis for the main steam supply lines to the turbine-driven auxiliary feedwater pumps" in SRP-LR Table 4.1-3 is not applicable to STP's CLB.

UFSAR Table 10.1-1 indicates that each STP unit is designed with three (3) motor-driven AFW pumps and one (1) turbine driven AFW pump. UFSAR Table 3.2.A-1 indicates that the main steam supply lines to the turbine-driven AFW pump were designed to either ASME Code Section III, Subarticle NC or ND design requirements for ASME Code Class 2 or 3 components.

-4 GALL AMR VIII.B1-10 identifies that cumulative fatigue damage/fatigue may be an aging effect requiring management for steel main steam piping that is exposed to a steam or secondary water environment and recommends that a TLAA be credited to manage this aging effect during the period of extended operation.

Issue:

The staff has verified that the ASME Code Section III, design code of record (1974 Edition inclusive of the Winter 1975 Addenda) did not require explicit CUF or It fatigue analyses of these main steam supply lines. However, the ASME Code Section III, Subarticle NC or ND requirements may have required the applicant to perform a maximum allowable stress range reduction analysis for the main steam supply lines to the turbine-driven AFW pump. In addition, LRA Section 4.3.5 identifies the maximum allowed stress range reduction analyses for the ASME Code Class 2 and 3 piping as TLAAs for the LRA. Thus, the staff is of the opinion that the applicant needs to provide further clarification and justification on why the maximum allowed stress range reduction TLAA discussed in LRA Section 4.3.5 would not be applicable to the main steam supply lines that supply steam to the turbine-driven AFW pump during a turbine-driven AFW pump actuation.

Reguest:

Clarify with supporting justification whether cumulative fatigue damage (or "cracking - fatigue")

is an applicable aging effect requiring management (AERM) for the main steam supply lines to the turbine-driven AFW pump. If cumulative fatigue damage (or "cracking - fatigue") is an applicable AERM for these lines, provide the basis on why maximum allowable stress range reduction TLAA in LRA Section 4.3.5 would not be identified as the appropriate TLAA for managing cumulative fatigue damage or "cracking - fatigue" in these lines consistent with GALL AMR VIII.B1-10 recommendations, and why the main steam lines to the turbine-driven AFW pump would not need to be within the scope of the maximum allowable stress range reduction analysis TLAA that is given in LRA Section 4.3.5.

RAI 4.1-5 (Absence of TlAA for Flow-Induced Vibrations)

Background:

LRA Table 4.1-2 and LRA Section 4.3.3 state the applicant's review of the CLB did not identify any time-dependent flow-induced vibration endurance limit analyses for the reactor vessel internals (RVI) components. The applicant states that the CLB does not describe any time-limited effects for a licensed operating period associated with flow-induced vibration, and that, therefore, there are not any TLAAs associated with flow-induced vibrations of the RVI components, when assessed against the TLAA definition criteria in 10 CFR 54.3(a), Criteria 2 and 3.

The STP flow-induced vibration analysis basis for RVI components is accounted for in the following sections and Tables of the UFSAR:

-5 Section 3.9.2.3, "Dynamic Response Analysis of Reactor Internals Under Operational Flow Transients and Steady-State Conditions" Section 3.9.2.4, "Preoperational Flow-Induced Vibration Testing of Reactor Internals" Section 3.9.2.6, "Correlations of Reactor Internals Vibration Tests with the Analytical Results" Section 1.6, "Material Incorporated By Reference," and Table 1.6-2, "Westinghouse Topical Reports Incorporated By Reference" - with the following WCAP Reports invoked by reference as part of the flow-induced vibration analysis basis:

Proprietary U.S. Nuclear Regulatory Commission {NRC)-Approved WCAP-8303-P-A, Revision 0, "Prediction of the Flow-Induced Vibration of Reactor Internals by Scale Model Tests" Proprietary NRC-Approved WCAP-8516-P-A, Revision 0, "UHI Plant Internals Vibration Measurement Program and Pre and Post Hot Functional Examinations" Proprietary NRC-Approved WCAP-8766-P-A, Revision 0, "Verification of Neutron Pad and 17 x 17 Guide Tube Designs by Preoperational Tests on the Trojan 1 Power Plant" Proprietary WCAP-9395-P, "4XL Scale Model Internal Flow Test Structural Response Test" - (UFSAR Section 1.5 indicates that this WCAP includes an assessment of the vibrational levels in the internals)

WCAP-9646, "Verification of Upper Head Injection Reactor Vessel Internals by Preoperational Test of the Sequoyah Power Plant" Proprietary WCAP-1 0865, "South Texas Plant (TGX) Reactor Internals Flow-Induced Vibration Assessment" Collectively, these UFSAR sections and tables indicate that the applicant uses conformance with the NRC's position in Regulatory Guide (RG) 1.20, "Comprehensive Vibration Assessment Program for Reactor Internals During Preoperational and Initial Startup Testing," as the basis for protecting the integrity of the RVI components against those aging effects that may be induced by flow-induced vibrations (e.g., cracking or loss of material by wear induced by the vibrations) and that the applicant uses Indian Point, Sequoyah, and Trojan flow-induced vibration programs and test data as the applicant's prototypical analysis basis for STP.

Issue:

LRA Section 4.3.3 does not provide a comprehensive summary of the total STP basis that is used to assure the integrity of the RVI components from the impacts of flow-induced vibrations.

Specifically, the applicant only makes a very general statement that the CLB did not include any flow-induced vibration analyses that would need to be identified as a TLAA for the LRA, and

- 6 supports this position with a statement that any flow-induced vibration analyses in the CLB either did not involve an assessment of an applicable aging effect (i.e., did not conform to 10 CFR 54.3 Criterion 2) or were not based on time-dependent assumptions defined by the life of the plant (i.e. did not conform to 10 CFR 54.3 Criterion 3). Although LRA Section 4.3.3 does reference the applicability of UFSAR Section 3.9.2.3, it fails to mention that the applicant's flow-induced vibration basis for the RVI components was based on conformance with the NRC position in RG 1.20 or that the flow-induced vibrational bases in UFSAR Sections 3.9.2.4 and 3.9.2.6 are also part of the applicant's RG 1.20 conformance basis. LRA Section 4.3.3 fails to identify which of the WCAP reports in UFSAR Table 1.6-2 (e.g., WCAP-8303-P-A, WCAP-8516-P-A, WCAP-8766-P-A, WCAP-9395-P, WCAP-9646, and WCAP-10865-P) are currently being relied upon as part of the applicant's current RG 1.20 conformance basis, or whether each of the analyses in these WCAP reports would need to be identified as TLAAs when compared to the six criteria for TLAAs in 10 CFR 54.3. LRA Section 4.3.3 also fails to mention that the applicant credits its plant-specific PWR Reactor Internals Program (i.e., LRA AMP B2.1.35) with the management of the aging effects that are applicable to the STP RVI components, including those that could be induced by a flow-induced vibration mechanism (e.g.,

cracking or loss of material). Thus, without further clarification, the staff is unable to confirm that the LRA would not need to include any TLAAs on flow-induced vibrations of the RVI components.

Request:

Part 1 - Clarify which edition of RG 1.20 is being used as the current basis for assessing flow-induced vibrations of the STP RVI components and provide a brief summary (i.e.,

clarification) on how the information in UFSAR Sections 3.9.2.3, 3.9.2.4, and 3.9.2.5 relates to the STP RG 1.20 conformance basis and to each other.

Part 2 -Identify which of the WCAPs in UFSAR Table 1.6-2 are currently being relied upon as part of the applicant's RG 1.20 conformance basis, and for those WCAPs that are credited for RG 1.20 conformance, provide a brief summary of all analyses, evaluations, or calculations that were included in each of these WCAP reports (if any) to support the STP RG 1.20 conformance basis and provide an assessment of these analyses, evaluations, or calculations against the TLAA identification criteria in 10 CFR 54.3.

Part 3 - Justify whether each analysis, evaluation, or calculation provided in response to Part 2 needs to be identified as a TLAA for the LRA under the TLAA identification requirements of 10 CFR 54.21(c)(1).

RAI4.1-7 (Exemption Identification Followup RAI)

Background:

LRA Section 4.1.4 states that the CLB includes seven exemptions in the CLB that were granted under the provisions of 10 CFR 50.12, and that of these exemptions, the exemption on the LBB analysis (which forms the applicant's basis for complying with "dynamic effect" analysis relaxation provisions in 10 CFR Part 50, Appendix A, General Design Criterion 4) was the only exemption that was based on a TLAA. In the applicant's letter of December 9, 2010, the

- 7 applicant provided its response to RAI 4.1-1 and identified that the exemption on use of Code Case N-514 should have been identified as an exemption for the LRA that conforms to the exemption identification requirement in 10 CFR 54.21 (c)(2) and amended the application to add the exemption on Code Case N-514 as an exemption that was based on a TLAA RAI4.1-1 has been resolved based on that LRA amendment.

Issue:

The staff has observed that in LRA Section (AMP) B2.1.15, "Reactor Vessel Surveillance," the applicant mentions that an exemption was granted in the original license from meeting the requirements of 10 CFR Part 50, Appendix H, but did not provide any discussion in the LRA on why this exemption would not need to be identified for the LRA under the criteria on 10 CFR 54.21 (c)(2). The staff has also observed that, in STP Letter No. NOC-AE-000518, dated July 13, 1999, the applicant requested NRC approval of numerous risk-informed exemptions from applicable requirements in 10 CFR, as based on the regulatory exemption acceptance provisions of 10 CFR 50.12, and that the applicant failed to make any mention of these risk informed exemptions in LRA Section 4.1.4. Thus, the staff still has difficulty determining exactly how many exemptions were granted to the applicant under the requirements of 10 CFR 50.12.

and of these exemptions, what the exemptions are based upon and how many remain in effect for the CLB and will need to be identified as exemptions that were granted under 10 CFR 50.12 and are based on a TLAA - as mandated by the license renewal application requirement in 10 CFR 54.21 (c)(2).

Request:

Part 1 - Provide a list of all exemptions that were granted in the CLB in accordance with the regulatory exemption criteria of 10 CFR 50.12. Of these exemptions, identify the regulation in 10 CFR for which each exemption was requested, and summarize what the exemption involved and whether it remains in effect for the CLB.

Part 2 - Provide the bases, with appropriate justifications, why each of the exemptions discussed in the response to Part 1 would not need to be identified as an exemption for the LRA pursuant to the exemption identification criterion in 10 CFR 54.21 (c)(2). Account for the 10 CFR Part 50, Appendix H-based exemption that is referred to in LRA Section B2.1.15 and the risked-informed exemptions that were requested in the applicant's letter of July 13, 1999 (i.e., STP Letter No. NOC-AE-000518) in these responses to RAI4.1-7, Parts 1 and 2.

Environmental Qualification of Electric Components (061)

RAI 4.4-1, Environmental Qualification of Electric Components (TLAA)

Background:

In LRA Section 4.4," Environmental Qualification (EQ) of Electric Components," the applicant stated that the program is consistent with the guidance of NUREG-588, Category 1, and the requirements of 10 CFR 50.49, with exemption from environmental scope for certain low-safety/risk significant (LSS) and non-risk significant (NRS) components.

- 8 10 CFR Part 49, "Environmental Qualification of Electric Equipment Important to Safety for Nuclear Power Plants," establishes a program for qualifying the electric equipment (e.g.,

safety-related electric equipment, non-safety-related electric equipment, and certain post accident monitoring equipment). By letters dated July 13, 1999, as supplemented October 14 and 22, 1999, January 26 and August 31, 2000, and January 15, 18, 23, March 19, May 8 and 21, 2001, (hereinafter, the submittal, Adams accession number ML011430090), STP Nuclear Operating Company requested an exemption from 10 CFR Part 49(b), to exclude LSS/NRS components from the scope of electrical equipment important to safety under 10 CFR 50.49(b).

The staff noted that § 54.21 c(2) states that a list must be provided of plant-specific exemptions granted pursuant to 10 CFR 50.12 and in effect that are based on TLAAs as defined in § 54.3.

The applicant is also required to provide an evaluation that justifies the continuation of these exemptions for the period of extended operation.

The staff also noted that 10 CFR 54.4(a) 1, states:

Plant systems, structures, and components within the scope of this part are safety-related systems, structures, and components which are those relied upon to remain functional during and following design-basis events (as defined in 10 CFR 50.49(b)(1>> to ensure the integrity of the reactor coolant pressure boundary; (and) the capability to prevent or mitigate the consequences of accidents which could result in potential offsite exposures comparable to those referred to in § 50.34(a)(1), § 50.67(b)(2), or § 100.11 of this chapter, as applicable.

The Statement of Considerations for the 10 CFR 54 final rule, Section IIl,c(iv), states regarding the use of probabilistic risk assessment in license renewal, that the Commission concluded that it was inappropriate to establish a license renewal scoping criterion that relies on plant-specific probabilistic analyses.

10 CFR Part 54.4, "Scope," requires the following:

(a) Plant systems, structures, and components within the scope of this part are-(1) Safety-related systems, structures, and components which are those relied upon to remain functional during and following design-basis events (as defined in 10 CFR 50.49 (b)(1>> to ensure the following functions-(i) The integrity of the reactor coolant pressure boundary; (ii) The capability to shut down the reactor and maintain it in a safe shutdown condition; or (iii) The capability to prevent or mitigate the consequences of accidents which could result in potential offsite exposures comparable to those referred to in

§ 50.34(a)(1), § 50.67(b)(2), or § 100.11 of this chapter, as applicable.

- 9 (2) All nonsafety-related systems, structures, and components whose failure could prevent satisfactory accomplishment of any of the functions identified in paragraphs (a)(1)(i), (ii), or (iii) of this section.

(3) All systems, structures, and components relied on in safety analyses or plant evaluations to perform a function that demonstrates compliance with the Commission's regulations for fire protection (10 CFR 50.48), environmental qualification (10 CFR 50.49), pressurized thermal shock (10 CFR 50.61), anticipated transients without scram (10 CFR 50.62), and station blackout (10 CFR 50.63).

Issue:

The applicant did not provide the plant-specific exemptions granted pursuant to 10 CFR 50.12 and in effect that are based on TLAAs as defined in § 54.3 and as applied to 10 CFR 50.49(b).

Furthermore, the applicant did not provide any evaluation that justifies the continuation of these exemptions for the period of extended operation. The staff is concerned that an exemption to 10 CFR 50.49(b) for electric equipment important to safety based on probabilistic risk assessment is inconsistent with the license renewal rule statement of considerations and 10 CFR Part 54.4 scoping, which utilizes deterministic criteria. Further, the staff is concerned that these exempted electric components are not included in the scope of license renewal, and therefore not subject to a TLAA or an associated aging management program and therefore, may not be capable of performing their intended function for the period of extended operation.

Request:

1. Provide a list of electrical and instrumentation and control system SSCs that were excluded from the scope of license renewal (10 CFR 54.4 (a)(1), (a)(2), and (a)(3>> as a result of special treatment requirements exemption of SSCs.

2. Provide a list of electrical and instrumentation and control system SSCs that have been exempted from 10 CFR 50.49(b), including SSC replacements, subject to 10 CFR 54.4.

3. Indicate whether the electrical and instrumentation and control system components for which the exemption for 10 CFR Part 50.49 was granted, are within the scope of license renewal. If not, provide justification for their exclusion. Include justification for the continuation of these exemptions into period of extended operation.

4. Describe any subsequent modifications or changes to either plant design or LSS/NRS components that revised LSS/NRS electrical and instrumentation and control component environmental conditions or qualification. If so, describe the modifications or changes incorporated into the aging management of the LSS/NRS electrical and instrumentation and control components.

5. Discuss how the specific management program/controls (inspection, tests, and surveillances) are adequate to provide aging management during the period of extended operation such that LSS/NRS electrical and instrumentation and control components are capable of performing their intended function under design basis conditions throughout the service life of the component

ML11250A043 LA: DLR/RPB1 I PM: DLR/RPB1 IBC: DLR/RPB4 SFigueroa JDaily DMorey JDaily DATE 09/21/2011 SFigueroa 09/21/2011 09/21/2011 09/22/2011 09/22/2011

Letter to G. T. Powell from John W. Daily dated September 22, 2011

SUBJECT:

REQUESTS FOR ADDITIONAL INFORMATION FOR THE REVIEW OF THE SOUTH TEXAS PROJECT, UNITS 1 AND 2 LICENSE RENEWAL APPLICATION - AGING MANAGEMENT REVIEW, SET 1 (TAC NOS. ME4936 AND ME4937)

DISTRIBUTION:

HARD COPY:

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