ML050260359

Summary of Telephone Conference Held on January 10, 2005, Between the U.S. Nuclear Regulatory Commission and Nuclear Management Company, LLC, Concerning Requests for Additional Information Pertaining to the Point Beach Nuclear Plant, Units

ML050260359
Person / Time
Site:	Point Beach
Issue date:	01/19/2005
From:	Veronica Rodriguez NRC/NRR/DRIP/RLEP
To:
Rodriguez VM, RLEP/DRIP/NRR, 415-3703
References
Download: ML050260359 (30)

Text

January 19, 2005 LICENSEE: Nuclear Management Company, LLC FACILITY: Point Beach Nuclear Plant, Units 1 and 2

SUMMARY

OF TELEPHONE CONFERENCE HELD ON JANUARY 10, 2005, BETWEEN THE U.S. NUCLEAR REGULATORY COMMISSION AND NUCLEAR MANAGEMENT COMPANY, LLC, CONCERNING REQUESTS FOR ADDITIONAL INFORMATION PERTAINING TO THE POINT BEACH NUCLEAR PLANT, UNITS 1 AND 2, LICENSE RENEWAL APPLICATION The U.S. Nuclear Regulatory Commission staff (the staff) and representatives of Nuclear Management Company, LLC (NMC) held a telephone conference on January 10, 2005, to discuss and clarify the staffs requests for additional information (RAIs) concerning the Point Beach Nuclear Plant, Units 1 and 2, license renewal application. The conference call was useful in clarifying the intent of the staffs RAIs. provides a listing of the meeting participants. Enclosure 2 contains a listing of the RAIs discussed with the applicant, including a brief description on the status of the items. contains draft responses provided by the applicant.

The applicant had an opportunity to comment on this summary.

/RA/

Verónica M. Rodríguez, Project Manager License Renewal Section A License Renewal and Environmental Impacts Program Division of Regulatory Improvement Programs Office of Nuclear Reactor Regulation Docket Nos. 50-266 and 50-301

Enclosures:

As stated cc w/encls: See next page

DOCUMENT NAME: E:\Filenet\ML050260359.wpd OFFICE PM:RLEP SC:RLEP NAME VRodríguez SLee DATE 01 / 14 / 05 01 /19 / 05 Point Beach Nuclear Plant, Units 1 and 2 cc:

Jonathan Rogoff, Esq. Mr. Jeffrey Kitsembel Vice President, Counsel & Secretary Electric Division Nuclear Management Company, LLC Public Service Commission of Wisconsin 700 First Street P.O. Box 7854 Hudson, WI 54016 Madison, WI 53707-7854 Mr. Frederick D. Kuester David Weaver President and Chief Executive Officer Nuclear Asset Manager We Generation Wisconsin Electric Power Company 231 West Michigan Street 231 West Michigan Street Milwaukee, WI 53201 Milwaukee, WI 53201 James Connolly John Paul Cowan Manager, Regulatory Affairs Executive Vice President & Chief Nuclear Point Beach Nuclear Plant Officer Nuclear Management Company, LLC Nuclear Management Company, LLC 6610 Nuclear Road 700 First Street Two Rivers, WI 54241 Hudson, WI 54016 Mr. Ken Duveneck Douglas E. Cooper Town Chairman Senior Vice President - Group Operations Town of Two Creeks Palisades Nuclear Plant 13017 State Highway 42 Nuclear Management Company, LLC Mishicot, WI 54228 27780 Blue Star Memorial Highway Covert, MI 49043 Chairman Public Service Commission Fred Emerson of Wisconsin Nuclear Energy Institute P.O. Box 7854 1776 I Street, NW., Suite 400 Madison, WI 53707-7854 Washington, DC 20006-3708 Regional Administrator, Region III Roger A. Newton U.S. Nuclear Regulatory Commission 3623 Nagawicka Shores Drive 801 Warrenville Road Hartland, WI 53029 Lisle, IL 60532-4351 James E. Knorr Resident Inspector's Office License Renewal Project U.S. Nuclear Regulatory Commission Nuclear Management Company, LLC 6612 Nuclear Road 6610 Nuclear Road Two Rivers, WI 54241 Point Beach Nuclear Plant Two Rivers, WI 54241

DISTRIBUTION: Note to Licensee: Nuclear Management Company, LLC, Re: Summary of telephone conference held on January 10, 2005, Dated: January 19, 2005 Adams Accession No.: ML050260359 HARD COPY RLEP RF E-MAIL:

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LIST OF PARTICIPANTS FOR TELEPHONE CONFERENCE TO DISCUSS THE POINT BEACH NUCLEAR PLANT, UNITS 1 AND 2 LICENSE RENEWAL APPLICATION JANUARY 10, 2005 Participants Affiliations J. Knorr Nuclear Management Company, LLC M. Morgan Nuclear Regulatory Commission G. Suber Nuclear Regulatory Commission V. Rodriguez Nuclear Regulatory Commission Enclosure 1

DRAFT REQUESTS FOR ADDITIONAL INFORMATION (RAI)

POINT BEACH NUCLEAR PLANT, UNITS 1 AND 2 LICENSE RENEWAL APPLICATION January 10, 2005 The U.S. Nuclear Regulatory Commission staff (the staff) and representatives of Nuclear Management Company, LLC (NMC) held a telephone conference call on January 10, 2005, to discuss and clarify the staffs requests for additional information (RAIs) concerning the Point Beach Nuclear Plant, Units 1 and 2, license renewal application (LRA). The following RAIs were discussed during the telephone conference call.

4.3 Metal Fatigue RAI-4.3.1 Reactor Vessel Structural Integrity Provide confirmation that the limiting locations of the PBNS reactor vessels evaluated for extended operation correspond to the structures and/or components listed in Table IV.A2 of NUREG-1801, Volume 2, for PWR reactor vessels structures and/or components, where cumulative fatigue damage/fatigue is the aging effect/mechanism, and which require further evaluation as TLAAs for the period of extended operation. Alternatively, provide the location in the LRA where this information is shown.

Discussion: The applicant clarified their draft response. The applicant will provide their formal response in writing.

RAI-4.3.2.1 Reactor Vessel Internals Structural Integrity Provide confirmation that the limiting locations of the PBNS reactor vessel internals evaluated for extended operation correspond to the structures and/or components listed in Table IV.B2 of NUREG-1801, Volume 2, for PWR reactor vessel internals structures and/or components, where cumulative fatigue damage/fatigue is the aging effect/mechanism, and which require further evaluation as TLAAs for the period of extended operation. Alternatively, provide the location in the LRA where this information is shown.

Discussion: The applicant clarified their draft response. The applicant will provide their formal response in writing.

RAI-4.3.2.2 Reactor Vessel Internals Structural Integrity Provide a summary of 60-year primary-plus-secondary stress intensities and cumulative fatigue usage factors (similar to revised Tables 4.3-1 and 4.3-2 in Appendix A of the LRA for components of the reactor vessel) for the key reactor internal components listed on page 4-41 of the LRA.

Discussion: The applicant clarified their draft response. The applicant will provide their formal response in writing.

Enclosure 2

RAI-4.3.3 Control Rod Drive Mechanism Structural Integrity Provide a comparison of the CLB set of transient conditions and design cycles, and the revised set of full power uprate transient conditions and design cycles, that were used in the CRDM fatigue TLAAs to show conformance with the CLB fatigue limits to the end of the period of extended operation.

Discussion: The applicant clarified their draft response. The applicant will provide their formal response in writing.

RAI-4.3.4.1 Steam Generator Structural Integrity Provide confirmation that the limiting locations of the PBNS steam generators evaluated for extended operation correspond to the structures and/or components listed in Table IV.D1 of NUREG-1801, Volume 2, for PWR reactor vessels structures and/or components, where cumulative fatigue damage/fatigue is the aging effect/mechanism, and which require further evaluation as TLAAs for the period of extended operation. Alternatively, state the location in the LRA where this information has been provided.

Discussion: The applicant clarified their draft response. The applicant will provide their formal response in writing.

RAI-4.3.4.2 Steam Generator Structural Integrity Provide a comparison of the CLB set of transient conditions and design cycles, and the revised set of Steam Generator Replacement and Full Power Uprate transient conditions and design cycles, that were used in the Units 1 and 2 steam generator fatigue TLAAs to show conformance with the CLB fatigue CUF limit to the end of the period of extended operation.

Alternatively, provide clarification stating that the applicable transient conditions and design cycles are those stated in Table 4.1-8 of Appendix A to the LRA.

Discussion: The applicant clarified their draft response. The applicant will provide their formal response in writing.

RAI-4.3.4.3 Steam Generator Structural Integrity List the key Units 1 and 2 steam generator components, and provide for each a summary of 60-year primary-plus-secondary stress intensities and cumulative fatigue usage factors (similar to revised Tables 4.3-1 and 4.3-2 in Appendix A of the LRA for components of the reactor vessel) for these components.

Discussion: The applicant clarified their draft response. The applicant will provide their formal response in writing.

RAI-4.3.5.1 Pressurizer Structural Integrity Provide confirmation that the limiting fatigue locations of the PBNS pressurizers evaluated for extended operation correspond to the pressurizer structures and/or components listed in Table IV.C2.5 of NUREG-1801, Volume 2, for PWR reactor vessels structures and/or components, Enclosure 2

where cumulative fatigue damage/fatigue is the aging effect/mechanism, and which require further evaluation as TLAAs for the period of extended operation. Alternatively, state the location in the LRA where this information has been provided.

Discussion: The applicant clarified their draft response. The applicant will provide their formal response in writing.

RAI-4.3.5.2 Pressurizer Structural Integrity Provide a comparison of the CLB set of transient conditions and design cycles, and the revised set of Steam Generator Replacement and Full Power Uprate transient conditions and design cycles, that were used in the Units 1 and 2 pressurizers fatigue TLAAs to show conformance with the CLB fatigue limit to the end of the period of extended operation.

Discussion: The applicant clarified their draft response. The applicant will provide their formal response in writing.

RAI-4.3.5.3 Pressurizer Structural Integrity Provide clarification that the plant-specific insurge/outsurge fatigue analyses are based on the combination of the insurge/outsurge transient condition and the transients listed in the revised set of Steam Generator Replacement and Full Power Uprate transient conditions.

Discussion: The applicant clarified their draft response. The applicant will provide their formal response in writing.

RAI-4.3.5.4 Pressurizer Structural Integrity Provide a description of the Modified Operating Procedures (page 4-45) that were used to minimize or eliminate in-surge/out-surge cycling.

Discussion: The applicant clarified their draft response. The applicant will provide their formal response in writing.

RAI-4.3.5.5 Pressurizer Structural Integrity List the key Units 1 and 2 pressurizer components, and provide for each a summary of 60-year primary-plus-secondary stress intensities and cumulative fatigue usage factors (similar to revised Tables 4.3-1 and 4.3-2 in Appendix A of the LRA for components of the reactor vessel) for these components.

Discussion: The applicant clarified their draft response. The applicant will provide their formal response in writing.

RAI-4.3.7 Pressurizer Surge Line Structural Integrity Provide a comparison of the CLB set of transient conditions and design cycles, and the revised set of Steam Generator Replacement and Full Power Uprate transient conditions and design Enclosure 2

cycles, that were used in the Units 1 and 2 pressurizer surge line fatigue TLAAs to show conformance with the CLB fatigue limit to the end of the period of extended operation.

Discussion: The applicant clarified their draft response. The applicant will provide their formal response in writing.

RAI-4.3.8 Pressurizer Spray Header Piping Structural Integrity This section states that: In view of the lack of margin with the Unit 1 piping system analysis results for end of life extension (EOLE), additional analysis investigations were pursued. The original 88-08 analysis incorporated simplified analysis techniques and assumptions. It was not clear that the analysis was in fact conservative. The 88-08 analyses were re-performed using the original temperature monitoring data, and refined analysis techniques and assumptions.

Provide a detailed description and basis of the refined analyses techniques and assumptions that were used in the 88-08 re-evaluation to reduce the 60-year CUF of 0.99 for the Unit 1 piping system to a 60-year CUF of 0.277.

Discussion: The applicant clarified their draft response. The applicant will provide their formal response in writing.

RAI- 4.3.10.1 Environmental Effects on Fatigue For the USAS B31.1 locations, provide a description of the PBNP-specific simplified ASME Section III fatigue analyses that were used to calculate environmentally based cumulative usage factors.

Discussion: The applicant clarified their draft response. The applicant will provide their formal response in writing.

RAI- 4.3.10.2 Environmental Effects on Fatigue The Pressurizer CUFs are determined based on EPRI MRP-47 methodology. The staff has not endorsed MRP-47. Provide the environmentally assisted CUFs for the Pressurizer locations, based on the staff-accepted methodology as stated in Sections 4.3.2.2 and 4.3.3.2 of NUREG-1800.

Discussion: The applicant clarified their draft response. The applicant will provide their formal response in writing.

ENCLOSURE Enclosure 2

RESPONSE TO POINT BEACH NUCLEAR PLANT, UNITS 1 AND 2 LICENSE RENEWAL APPLICATION (LRA)

REQUESTS FOR ADDITIONAL INFORMATION (RAls)

(Non-Proprietary)

The following information is provided in response to the Nuclear Regulatory Commission (NRC) staff's request for additional information (RAI) regarding License Renewal Application.

The NRC staff's questions are restated below, with the Nuclear Management Company (NMC) response following.

4.3 Metal Fatigue NRC Question RAI-4.3.1:

Reactor Vessel Structural Integrity Provide confirmation that the limiting locations of the PBNS reactor vessels evaluated for extended operation correspond to the structures and/or components listed in Table IV.A2 of NUREG-1801, Volume 2, for PWR reactor vessels structures and/or components, where cumulative fatigue damage/fatigue is the aging effect/mechanism, and which require further evaluation as TLAAs for the period of extended operation. Alternatively, provide the location in the LRA where this information is shown.

NMC Response:

As noted in the following table, the limiting locations of the PBNP RPVs evaluated for extended operation correspond to the structures and/or components listed in Table IV.A2 of NUREG-1801, Volume 2, for PWR reactor vessel structures and/or components, where cumulative fatigue damage/fatigue is the aging effect/mechanism.

Enclosure 3

NUREG-1801 RPV Components (1)

Table IV.A2 Component Description Evaluated for Fatigue at PBNP Item A2.1-b Closure Head:

- Dome Yes A2.1-e Closure Head:

- Stud Assembly Yes A2.2-c Control Rod Drive Head Penetration:

- Nozzle Yes

- Pressure Housing Yes A2.3-c Nozzles:

- Inlet Yes

- Outlet Yes

- Safety Injection Yes A2.4-a Nozzle Safe Ends:

- Inlet Yes (2)

- Outlet Yes (2)

- Safety Injection Yes (2)

A2.5-d Vessel shell:

- Upper (nozzle) Shell Yes

- Intermediate and Lower Shell Yes

- Vessel Flange Yes

- Bottom Head Yes A2.8-a Pressure Vessel Support:

- Skirt Support Yes (3)

(1) - Reactor Vessel structures and/or components listed in Table IV.A2 of NUREG-1801, Volume 2, for PWR reactor vessels structures and/or components.

(2) - Included with specific nozzle analyses.

(3) - PBNP RPVs are supported off of external support brackets at the nozzle elevation.

NRC Question RAI-4.3.2.1:

Reactor Vessel Internals Structural Integrity Provide confirmation that the limiting locations of the PBNS reactor vessel internals evaluated for extended operation correspond to the structures and/or components listed in Table IV.B2 of NUREG-1801, Volume 2, for PWR reactor vessel internals structures and/or components, where cumulative fatigue damage/fatigue is the aging effect/mechanism, and which require further evaluation as TLAAs for the period of extended operation. Alternatively, provide the location in the LRA where this information is shown.

Enclosure 3

NMC Response:

The following table identifies the structures and/or components listed in Table IV.B2 of NUREG-1801, Volume 2, for PWR reactor vessel internals structures and/or components, where cumulative fatigue damage/fatigue is the aging effect/mechanism. The table also identifies if the PBNP reactor vessel internals component location was evaluated for fatigue for extended operation. The major components have been evaluated for fatigue for extended operation.

Since the PBNP reactor internals were designed and manufactured prior to the release of Subsection NG of the ASME Code Section III, fatigue evaluations were not performed for all of the locations noted in Table IV.B2 of NUREG-1801, Volume 2, for PWR reactor vessel internals structures and/or components, where cumulative fatigue damage/fatigue is the aging effect/mechanism.

NUREG-1801 Reactor Vessel Internals (PWR) - Westinghouse (1)

Table IV.B2 Component Description Evaluated for Fatigue at PBNP Item B2.1-c Upper Internals Assembly:

- Upper Support Plate Yes

- Upper Core Plate Yes

- Hold-Down Spring No (2)

B2.1-h Upper Internals Assembly:

- Upper Support Column Yes B2.1-m Upper Internals Assembly:

- Fuel Alignment Pins No (2)

B2.2-c RCCA Guide Tube Assemblies:

- RCCA Guide Tubes Yes B2.2-f RCCA Guide Tube Assemblies:

- RCCA Guide Tube Bolts No (2)

- RCCA Guide Tube Support Pins Yes B2.3-d Core Barrel:

- Core Barrel (CB) Yes

- CB Flange (upper) Yes

- CB Outlet Nozzles Yes

- Thermal Shield Yes Baffle/Former Assembly:

B2.4-g - Baffle and Former Plates No (2)

- Baffle/Former Bolts Bolt Qualification by Testing B2.5-d Lower Internal Assembly:

- Lower Core Plate Yes

- Lower Support Plate Columns Yes Enclosure 3

B2.5-j Lower Internal Assembly:

- Fuel Alignment Pins No (2)

- Lower Support Plate Column No (2)

Bolts B2.5-p Lower Internal Assembly:

- Radial Keys and Clevis Inserts Yes

- Clevis Insert Bolts No (2)

(1) - Reactor Vessel Internals (PWR) - Westinghouse, structures and/or components listed in Table IV.B2 of NUREG-1801, Volume 2, for PWR reactor vessels structures and/or components.

(2) - Prior to the release of Subsection NG of the ASME Code Section III, the reactor vessel internals were designed to the intent of Subsection NB which was a pressure vessel code. The PBNP reactor internals were designed and manufactured prior to the release of Subsection NG of the ASME Code Section III. During this period, several sets of internals were being designed and manufactured at or about the same time. The reactor internals designs were segregated as 2-loop, 3-loop and 4-loop, but plant specific design packages and calculations were not produced. There were no ASME code design specifications or stress reports developed for the internal packages manufactured prior to Subsection NG. Typically, hand calculations were performed for the various subcomponents of the internals. Many of the individual subcomponent calculations were assembled into a single document, which is identified as the Westinghouse 2-Loop Design Manual. When a particular design feature was changed, new calculations would be performed to demonstrate the adequacy of the changed component. For components that were not changed, the original design and drawings continue to apply. With this evolutionary approach, and without Subsection NG requirements, the plant specific documentation is less than would be expected by current standards.

NRC Question RAI-4.3.2.2:

Reactor Vessel Internals Structural Integrity Provide a summary of 60-year primary-plus-secondary stress intensities and cumulative fatigue usage factors (similar to revised Tables 4.3-1 and 4.3-2 in Appendix A of the LRA for components of the reactor vessel) for the key reactor internal components listed on page 4-41 of the LRA.

NMC Response:

In accordance with our discussions with your staff on October 28th, 2004, a summary of 60-year primary-plus-secondary stress intensities for the PBNP reactor vessel internals will not be provided. The staff indicated that the summary of 60-year primary-plus-secondary stress intensities was not critical for the review. The summary of 60-year primary-plus-secondary stress intensities is also not a part of the PBNP CLB.

A summary of the PBNP reactor vessel internals key component fatigue evaluation results is included in the following table.

Enclosure 3

PBNP Reactor Vessel Internals Key Component Design Basis Fatigue Results Summary Component Description CUF Upper Support Plate Perforations [ ] (1)

Upper Core Plate alignment Pins [ ] (1)

Upper Core Plate [ ] (2)

Upper Support Column / Base Weld [ ] (1)

RCCA Guide Tube Sheath Weld [ ] (1)

Guide Tube Flange Weld [ ] (2)

Lower Support Plate/ CB Weld [ ] (2)

CB / Flange Weld [ ] (2)

Outlet Nozzle Inner Weld [ ] (1)

Thermal Shield Flexures [ ] (1)

Thermal Shield Flexure Bolts [ ] (1)

Lower Core Plate SC Bolt Holes [ ] (2)

Lower Support Column Extensions [ ] (2)

Lower Radial Restraint Dowel Pin [ ] (1)

Flexureless Insert [ ]

BRACKETED NUMBERS ARE WESTINGHOUSE PROPRIETARY (1) WCAP-14459 (2) PBNP Power Uprate Engineering Report NRC Question RAI-4.3.3:

Control Rod Drive Mechanism Structural Integrity Provide a comparison of the CLB set of transient conditions and design cycles, and the revised set of full power uprate transient conditions and design cycles, that were used in the CRDM fatigue TLAAs to show conformance with the CLB fatigue limits to the end of the period of extended operation.

NMC Response:

The revised set of full power uprate transient conditions and design cycles is PBNPs CLB set of transient conditions and design cycles. These are shown in the revised Table 4.1-8 Thermal and Loading Cycles in Appendix A FSAR Supplement of the PBNP LRA. This set of transient conditions and design cycles were used in the evaluation of all PBNP TLAAs that required the use of transient conditions and design cycles. This set of transient conditions and design cycles were used in the CRDM fatigue TLAA evaluation to show conformance with the CLB fatigue limits to the end of extended life (EOEL).

NRC Question RAI-4.3.4.1:

Steam Generator Structural Integrity Enclosure 3

Provide confirmation that the limiting locations of the PBNS steam generators evaluated for extended operation correspond to the structures and/or components listed in Table IV.D1 of NUREG-1801, Volume 2, for PWR reactor vessels structures and/or components, where cumulative fatigue damage/fatigue is the aging effect/mechanism, and which require further evaluation as TLAAs for the period of extended operation. Alternatively, state the location in the LRA where this information has been provided.

NMC Response:

As noted in the following table, the locations of the PBNP steam generators evaluated for extended operation correspond to the structures and/or components listed in Table IV.D1 of NUREG-1801, Volume 2, for PWR reactor vessel internals structures and/or components, where cumulative fatigue damage/fatigue is the aging effect/mechanism.

NUREG-1801 Steam Generator Components (1)

Table Evaluated for Fatigue at PBNP IV.D1 Component Description Item Unit 1 (44F) Unit 2 (47)

D1.1-a Pressure Boundary and Structural:

- Top Head Yes Yes

- Steam Nozzle Yes Yes

- Safe End Yes Yes D1.1-b Pressure Boundary and Structural:

- Upper and Lower Shell Yes Yes

- Transition Cone Yes Yes

- FW Nozzle Yes Yes

- Safe End Yes (5) Yes (5)

- FW Impingement Plate and Support N/A (2) N/A (2)

D1.1-h Pressure Boundary and Structural:

- Lower Head Yes Yes

- Primary Nozzles Yes Yes

- Safe Ends Yes (4) Yes (4)

D1.2-d Tube Bundle:

- Tubes Yes Yes

- Sleeves N/A (3) N/A (3)

(1) - Steam Generator structures and/or components listed in Table IV.D1 of NUREG-1801, Volume 2, for PWR reactor vessels structures and/or components.

(2) - The 44F and 47 replacement steam generators are feed ring designs and have no impingement plates.

(3) - There are no sleeved tubes in the PBNP steam generators.

(4) - The Unit 1 SGs safe ends are stainless steel weld buildup, Unit 2 steam generators contain stainless steel safe ends. The safe ends were analyzed with the nozzle.

Enclosure 3

(5) - The feedwater nozzles do not have a nozzle-to-piping safe end. The feedwater nozzles do have a safe end in the nozzle-to-thermal sleeve. The thermal sleeve safe ends were included in the nozzle analysis.

NRC Question RAI-4.3.4.2:

Steam Generator Structural Integrity Provide a comparison of the CLB set of transient conditions and design cycles, and the revised set of Steam Generator Replacement and Full Power Uprate transient conditions and design cycles, that were used in the Units 1 and 2 steam generator fatigue TLAAs to show conformance with the CLB fatigue CUF limit to the end of the period of extended operation.

Alternatively, provide clarification stating that the applicable transient conditions and design cycles are those stated in Table 4.1-8 of Appendix A to the LRA.

NMC Response:

The revised set of full power uprate transient conditions and design cycles is PBNPs CLB set of transient conditions and design cycles. These are shown in the revised Table 4.1-8 Thermal and Loading Cycles in Appendix A FSAR Supplement of the PBNP LRA. This set of transient conditions and design cycles were used in the evaluation of all PBNP TLAAs that required the use of transient conditions and design cycles. This set of transient conditions and design cycles were used in the steam generator fatigue TLAA evaluation to show conformance with the CLB fatigue limits to the end of license extension (EOEL).

NRC Question RAI-4.3.4.3:

Steam Generator Structural Integrity List the key Units 1 and 2 steam generator components, and provide for each a summary of 60-year primary-plus-secondary stress intensities and cumulative fatigue usage factors (similar to revised Tables 4.3-1 and 4.3-2 in Appendix A of the LRA for components of the reactor vessel) for these components.

NMC Response:

In accordance with our discussions with your staff on October 28th, 2004, a summary of 60-year primary-plus-secondary stress intensities for the PBNP steam generators will not be provided.

The staff indicated that the summary of 60-year primary-plus-secondary stress intensities was not critical for the review. The summary of 60-year primary-plus-secondary stress intensities is also not a part of the PBNP CLB. A summary of the PBNP steam generators key component fatigue evaluation results is included in the following table.

It should be noted that the design of the steam generators between the units at PBNP are not identical. The Unit 1 steam generators are an early 80s vintage, incorporating bounding generic analyses based on the Westinghouse 41 series steam generator design. The Unit 2 steam generators are a mid 90s vintage, incorporating a PBNP specific design analysis.

PBNP Steam Generator Key Components Design Basis Fatigue Results Summary Enclosure 3

Component Description Unit 1 (44F) Unit 2 (47)

CUF CUF Tube(s) [ ] (1) [ ] (1)

Tube-to-Tubesheet Weld [ ] (3) [ ] (4)

Primary Chamber, Tubesheet, and Stub Barrel [ ] (1) [ ] (4)

Primary Nozzle(s) [ ] (3) [ 2] (4)

Primary Manway Openings [ ] (3) [ ] (4) (6)

Divider Plate [ ] (2) [ ] (4)

Steam Nozzle, Upper Head, Upper Shell [ 1] (3) [ ] (1)

Steam Nozzle Venturi [ 8] (3) [ ] (4)

Feedwater Nozzle [ ] (1) [ ] (1)

Transition Cone [ ] (7) [ ] (1)

Secondary Manway Opening [ ] (8) [ ] (4)

Secondary Handholes / Access Openings [ ] (1) [ ] (4)

Secondary Inspection Ports [ ] (1)(5) [ ] (4)

Minor Penetrations [ ] (3) [ ] (4)

BRACKETED NUMBERS ARE WESTINGHOUSE PROPRIETARY (1) - PBNP Power Uprate Report (2) - WCAP-14602 PBNP Unit 2 SG Replacement Engineering Report (3) - WNEP-8393 (Unit 1 SG Stress Report)

(4) - WNEP-9513 (Unit 2 SG Stress Report)

(5) - The limiting location shown is the bolts. These are managed by replacement on a periodic basis. The next limiting location is the manway pad with a CUF of [ ].

(6) - The bolts and drain hole are qualified for fatigue based on tests. The CUF shown is for the cover and Pad Knuckle.

(7) - WTD-EM-79-039 (8) - WNEP-8393, The value for the inside radius of the steam nozzle is bounding.

Enclosure 3

NRC Question RAI-4.3.5.1:

Pressurizer Structural Integrity Provide confirmation that the limiting fatigue locations of the PBNS pressurizers evaluated for extended operation correspond to the pressurizer structures and/or components listed in Table IV.C2.5 of NUREG-1801, Volume 2, for PWR reactor vessels structures and/or components, where cumulative fatigue damage/fatigue is the aging effect/mechanism, and which require further evaluation as TLAAs for the period of extended operation. Alternatively, state the location in the LRA where this information has been provided.

NMC Response:

As noted in the following table, the fatigue locations of the PBNP pressurizers evaluated for extended operation correspond to the pressurizer structures and/or components listed in Table IV.C2.5 of NUREG-1801, Volume 2, for PWR reactor vessels structures and/or components, where cumulative fatigue damage/fatigue is the aging effect/mechanism.

NUREG-1801 Pressurizer Components (1)

Table IV.C2.5 Component Description Evaluated for Fatigue at PBNP Item C2.5-a Pressurizer:

- Shell Yes

- Heads Yes C2.5-d Pressurizer:

- Spray Line Nozzle Yes

- Spray Head No (2)

C2.5-e Pressurizer:

- Surge line nozzle Yes C2.5-f Pressurizer:

- Thermal sleeves Yes

- Instrument penetrations Yes

- Safe ends Yes C2.5-q Pressurizer:

- Heater Sheaths Yes

- Heater Sleeves Yes C2.5-t Pressurizer:

- Support keys No (N/A for PBNP) (3)

- Skirt Yes

- Shear Lugs No (N/A for PBNP) (3)

C2.5-w Pressurizer:

- Integral Support No (N/A for PBNP) (3)

(1) - Pressurizer structures and/or components listed in Table IV.C2.5 of NUREG-1801, Volume 2, for PWR reactor vessels structures and/or components.

Enclosure 3

(2) - The spray head is a non-structural or pressure retaining component, and is not in the scope of License Renewal.

(3) - The PBNP pressurizers do not have support keys, shear lugs, or intergral supports.

NRC Question RAI-4.3.5.2:

Pressurizer Structural Integrity Provide a comparison of the CLB set of transient conditions and design cycles, and the revised set of Steam Generator Replacement and Full Power Uprate transient conditions and design cycles, that were used in the Units 1 and 2 pressurizers fatigue TLAAs to show conformance with the CLB fatigue limit to the end of the period of extended operation.

NMC Response:

The revised set of full power uprate transient conditions and design cycles is PBNPs CLB set of transient conditions and design cycles. These are shown in the revised Table 4.1-8 Thermal and Loading Cycles in Appendix A FSAR Supplement of the PBNP LRA. This set of transient conditions and design cycles were used in the evaluation of all PBNP TLAAs that required the use of transient conditions and design cycles. This set of transient conditions and design cycles were used in the pressurizer fatigue TLAA evaluation to show conformance with the CLB fatigue limits to the end of extended life (EOEL).

NRC Question RAI-4.3.5.3:

Pressurizer Structural Integrity Provide clarification that the plant-specific insurge/outsurge fatigue analyses are based on the combination of the insurge/outsurge transient condition and the transients listed in the revised set of Steam Generator Replacement and Full Power Uprate transient conditions.

NMC Response:

The plant-specific insurge/outsurge fatigue analysis was based on a combination of the actual insurge/outsurge transients and other loadings experienced by the pressurizer and surge line components. Projections were made backward and forward in time to estimate the cumulative fatigue usage for these components for the entire 60-year operating life.

Extensive experience with fatigue monitoring has demonstrated that a significant system temperature differential (the difference between pressurizer water temperature and RCS hot leg temperature) is required to produce thermal fatigue in the surge line and lower head. This occurs during plant heatups and cooldowns. Other transients such as a reactor trip do not produce stresses above the minimum fatigue threshold.

Several types of loadings contribute to heatup and cooldown transients, including:

3. Internal pressure

4. Surge line piping thermal expansion Enclosure 3

5. Surge line piping thermal stratification

6. Thermal shock, or insurge/outsurge temperature transients from flow reversals The FatiguePro software installed at Point Beach-1/2 was utilized to evaluate these effects on the pressurizer locations affected by the insurge/outsurge transients.

FatiguePro computes stresses in various fatigue-sensitive components based on real plant data. A computational scheme was devised to compute the water temperature at various zones in the surge line and pressurizer lower head based on available temperatures, flows and other applicable instruments to capture any insurge/outsurge effect that the plant may experience during operation.

The following locations in the surge line and pressurizer lower head are monitored:

q Hot Leg Surge Nozzle q Pressurizer Surge Nozzle q Pressurizer Heater Penetration Weld q Pressurizer Water Temperature Instrument Nozzle The pressurizer heater penetration weld was shown to be the bounding location for fatigue usage in the surge line and pressurizer lower head. Plant data was available for Point Beach Units 1 and 2 from 1994 to present. The data was screened for heatup and cooldown transients to be analyzed in FatiguePro. A cooldown followed by a heatup was assumed to represent a cycle.

Fatigue Usage Projections Fatigue usage projections were based on the assumed number of future cycles that the plant will experience. For the purpose of projecting future fatigue usage, the incremental usage for a cooldown/heatup cycle was assumed to be the average incremental fatigue from the template periods.

The projected number of pressurizer heatups for the life of the plant is 100 for Unit 1 and 90 for Unit 2. Using these values and the average incremental fatigue usage for the periods in question, the projected fatigue usage for each location of interest were computed.

Backward Projections Because the Point Beach plants may have operated at a higher system DT than in the template period of available plant data, a sensitivity analysis was performed, to account for the possibly higher average incremental fatigue usage in the earlier time period.

For the time period before data was available, some Point Beach heatups and cooldowns were assumed to be at higher maximum system DTs than current operation for conservatism.

A sensitivity analysis was performed by running simulated data with higher DTs (by lowering the hot leg temperature) to determine a correlation between maximum DT and an increased fatigue usage factor.

Increases in fatigue usage were small. The hot leg temperature was reduced by 100°F (which has the effect of increasing the maximum DT by the same amount). This resulted in a relatively Enclosure 3

small increase in average incremental fatigue usage for the highest usage location, the pressurizer heater weld.

In most cases the fatigue usage was dependent primarily on the temperature trace of the pressurizer water temperature, the rate of which is not expected to change significantly during operations with different system DTs and relatively few significant insurges and outsurges.

However, it was considered conservative to assume that on the average, increased system DTs during the earlier time frame resulted in a maximum 50% increase from the current operations average incremental fatigue usage.

q For Unit 1, 53 RCS cooldown cycles occurred before 1994 q For Unit 2, 39 RCS cooldown cycles occurred before 1994 Projections The 50% increase was assumed to apply to the first 53 cycles for Unit 1 (39 for Unit 2). In reality, only approximately 100 heatup/cooldown cycles for Unit 1 are expected for the plant based on the frequency of past heatup/cooldown occurrences (90 cycles for Unit 2).

The Point Beach operation during heatup and cooldown is relatively benign, because large system temperature differentials (DTs) do not occur. In most cases the DT is less than 150°F.

Therefore, any amount of insurge/outsurge due to flow reversal is unlikely to contribute significantly to fatigue usage.

Environmental Effects The fatigue usage projections discussed above were adjusted for the maximum effect of environmental fatigue by multiplying by 15.35. The resulting environmental cumulative usage factors are acceptable (less than 1.0), and are shown in the LRA Table 4.3.10.2.

NRC Question RAI-4.3.5.4:

Pressurizer Structural Integrity Provide a description of the Modified Operating Procedures (page 4-45) that were used to minimize or eliminate in-surge/out-surge cycling.

NMC Response:

PBNP follows a water solid heatup/cooldown method for both units. The operating procedures set a maximum allowable delta T limit of 210°F between the RCS hot leg and the pressurizer liquid space. This ensures that operation of the plant is within the delta T limit assumed in the surge line thermal stratification analyses.

Enclosure 3

NRC Question RAI-4.3.5.5:

Pressurizer Structural Integrity List the key Units 1 and 2 pressurizer components, and provide for each a summary of 60-year primary-plus-secondary stress intensities and cumulative fatigue usage factors (similar to revised Tables 4.3-1 and 4.3-2 in Appendix A of the LRA for components of the reactor vessel) for these components.

NMC Response:

In accordance with our discussions with your staff on October 28th, 2004, a summary of 60-year primary-plus-secondary stress intensities for the PBNP pressurizers will not be provided. The staff indicated that the summary of 60-year primary-plus-secondary stress intensities was not critical for the review. The summary of 60-year primary-plus-secondary stress intensities is also not a part of the PBNP CLB. A summary of the PBNP pressurizers key component fatigue evaluation results is included in the following table.

PBNP Pressurizer Key Component Design Basis Fatigue Results Summary Component Description CUF Upper Head and Shell [ ] (1)

Lower Head Perforation [ ] (1)

Spray Nozzle [ ] (1)

Surge Nozzle [ ] (1)

Instrument Nozzle [ ] (1)

Lower Head Heater Well [ ] (1)

Immersion Heater [ ] (1)

Support Skirt and Flange [ ] (1)

Safety and Relief Nozzle [ ] (1)

Manway Pad [ ] (1)

Manway Cover [ ] (1)

Manway Bolts [ ] (1)

BRACKETED NUMBERS ARE WESTINGHOUSE PROPRIETARY (1) PBNP Power Uprate Engineering Report Enclosure 3

NRC Question RAI-4.3.7:

Pressurizer Surge Line Structural Integrity Provide a comparison of the CLB set of transient conditions and design cycles, and the revised set of Steam Generator Replacement and Full Power Uprate transient conditions and design cycles, that were used in the Units 1 and 2 pressurizer surge line fatigue TLAAs to show conformance with the CLB fatigue limit to the end of the period of extended operation.

NMC Response:

Westinghouse performed the original PBNP surge line thermal stratification evaluations.

The analysis results are documented in WCAP-13509 and WCAP-13510, "Structural Evaluation of the Point Beach Units 1 and 2 Pressurizer Surge Lines, Considering the Effects of Thermal Stratification," dated October 1992. WCAP-13509 is the Westinghouse Proprietary Class 2 version of the analysis and WCAP-13510 is the Westinghouse Proprietary Class 3 version.

Copies of both WCAP-13509 and WCAP-13510 were transmitted to the NRC in Wisconsin Electric letter VPNPD-92-360, NRC-92-139, November 24, 1992, Docket 50-266 and 50-301, Completion of the Reporting Requirements for Action Item 1.d of NRC IE Bulletin 88-11 (TACs 72155 and 72156) Point Beach Nuclear Plant Units 1 and 2. The specific analysis transient conditions and design cycles are detailed in the noted WCAPs.

Westinghouse evaluated the impacts of the changes in the RCS conditions, thermal design transients, and a 60-year life on the PBNP surge line thermal stratification analyses. The impact of changes in the revised RCS conditions, thermal design transients, and the 60-year life extension were factored into determining the ASME stress levels and allowables for the surge line. The evaluation included a review of the fatigue analysis and the stratification loadings that were transmitted to the pressurizer nozzle from the surge line piping. The changes and the percent increases for the thermal design transients were tabulated and the impact on the fatigue usage factor was calculated. The forces and moments that were generated by the stratified conditions in the surge line also exist at the pressurizer nozzle. The power uprate conditions were reviewed to determine if the old enveloping loads on the nozzle changed significantly. Temperature differences between the hot leg and pressurizer were used to calculate stratified moments in the surge line piping. The difference between the old Thot (hot leg temperature) and the new Thot was determined and used in the determination of new nozzle loads.

The results of the evaluation for the pressurizer surge line stratification showed that the power uprate conditions changed the fatigue usage factor at the location of highest usage factor by a negligible amount. The calculated change in loadings on the pressurizer nozzle due to stratification for the power uprate conditions was not considered significant. The results presented in WCAP-13509 and WCAP-13510 remain unchanged.

NRC Question RAI-4.3.8:

Pressurizer Spray Header Piping Structural Integrity This section states that: In view of the lack of margin with the Unit 1 piping system analysis results for end of life extension (EOLE), additional analysis investigations were pursued. The original 88-08 analysis incorporated simplified analysis techniques and assumptions. It was not clear that the analysis was in fact conservative. The 88-08 analyses were re-performed using the original temperature monitoring data, and refined analysis techniques and assumptions.

Enclosure 3

Provide a detailed description and basis of the refined analyses techniques and assumptions that were used in the 88-08 re-evaluation to reduce the 60-year CUF of 0.99 for the Unit 1 piping system to a 60-year CUF of 0.277.

NMC Response:

The refined analysis techniques and assumptions referred to evaluation of actual thermocouple data and to use of special purpose programs for performing piping analysis. Details are discussed below.

In late 1989 as a response to the NRC Bulletin 88-08 issues, Point Beach installed two sets of three thermocouples on the horizontal section of the Unit 2 main and auxiliary spray piping to detect leakage and thermal stratification in the lines. These thermocouple sets were installed near the tee joining the auxiliary pressurizer spray line to one of the main spray lines.

Thermally stratified conditions were discovered during heatup and normal operation. Using this data, Sargent and Lundy (S&L) performed a 40-year fatigue calculation for both units for the main and auxiliary spray piping, resulting in a fatigue usage in Unit 1 of 0.66, and 0.30 for Unit

2. 60-year projections of the Unit 2 fatigue usage yielded a value of 0.99. The S&L calculation included a simplified hand calculation of the thermal stratification stresses. The simplifying assumptions used may or may not have been conservative.

Review of the S&L work to determine a more accurate fatigue usage for a 60-year design life for Unit 1 consisted of:

2. Reviewing the thermocouple data to verify the basis for the stresses and contributions to fatigue of the operating parameters. The rationale for extrapolating the results of the data collection sample period to the entire plant life was revisited. Contributions to fatigue usage attributed to heatup, cooldown, auxiliary spray actuation, and thermal stratification due to valve leakage were identified.

4. Reviewing the simplified hand calculation of the thermal stratification stresses done by S&L.

These calculations contained estimates of global bowing moment, radial local stress, and axial local stress. Some of the simplifying assumptions used were conservative and some were possibly not conservative. The correct thermal stratification stresses are determined using the Structural Integrity (SI) program TOPBOT.

Thermal stratification data was collected for a 153-day period, beginning with a plant heatup.

The thermocouple data indicated that thermal stratification was present during most of the monitoring period, and the magnitude of the top-to-bottom gradient varied over time. The midlevel temperature, assumed to be indicative of the pipe average temperature, also varied over time, not only due to plant heatup but also due to variations in spray demand. Thus, two types of thermal cycling occur: global thermal cycling, based on the mid-pipe temperature variations, which affects the thermal expansion moments in the pipe and the global stratification bowing effects; and thermal gradient cycling, based on the variation of the difference between the top and bottom pipe temperatures, which affects the local and global thermal stratification stresses.

In the S&L analysis, node point 210 in Unit 1 was identified as the limiting location for stress and fatigue usage. Node point 210 is located on the 3-inch line between the first main spray tee and the reducer before the second tee. Because the calculations affect all locations proportionally, point 210 remained limiting and was used for determining the 60-year fatigue usage.

Enclosure 3

The thermocouple data was reviewed in detail and temperature cycles were constructed. Two types of cycles were constructed: Type A cycles, which are thermal expansion moment cycles based on the midlevel pipe temperature variations; and Type B, local and global thermal stratification cycles, based on the top-to-bottom thermal gradient magnitude variations. Type A cycles of less than 100°F and type B cycles of less than 50°F are neglected. The peaks and valleys of these cycles were paired according to the ASME method of matching highest peak with lowest valley, second highest peak with second lowest valley, etc. This was conservative because higher cyclic ranges produce exponentially higher fatigue usage.

The most severe top-to-bottom thermal stratification temperature profile is determined and modeled in the SI program TOPBOT. TOPBOT calculates the fixed end thermal bowing moment and the local peak stresses due to the nonlinear, non-axisymmetric thermal gradient.

The bowing moment was compared to that determined by S&L, and piping stresses that were determined were scaled according to the more accurate moment determined by TOPBOT.

These results, and the local peak stresses determined by TOPBOT, were then scaled to the varied cycle amplitudes to develop stress cycles. These results were used in a revised fatigue usage calculation to determine the projected fatigue usage for a 60-year plant life.

The thermal stratification appears to have been caused by leakage past auxiliary spray isolation valve CV-296. Although the leakage flow may initially be hot, as it is taken from the charging system, the flow is sufficiently small and the valve is far enough away (80 feet) from the main spray tee that the leakage mixes with the stagnant fluid in the auxiliary spray line and arrives at the tee at containment ambient temperature. Although preventive maintenance, including changes to the internals, was performed on valve CV-296 after measurement of the stratification, and it was unlikely that leakage continued to occur to the degree that was measured, it was conservatively assumed that the same amount of leakage and consequent magnitude of stratification continued to exist for the remainder of plant life.

It was also assumed that the 153-day period of data was representative of all plant operation.

This assumption was conservative because this 153-day period included a heatup, which contained many more stress cycles than did normal steady state operation. The heatup was also considered representative of a cooldown, because the mean pipe temperature range is the same, and there are multiple main spray and auxiliary spray actuations, as well as numerous variations in spray flow rate. Heatups tend to contain more thermal cycles than cooldowns, as there are typically more procedural steps, hold points, and tests conducted than during cooldown. To extrapolate the 153-days of cycles to 60 years of operation, the following assumptions were used:

q The cycles are considered to be repeated every 153 days of operation, despite the fact that plant heatups do not occur that often q The plant was not operated for one month per two years due to refueling outages S&L calculated the global thermal stratification fixed end moment, and the local thermal stratification stresses due to the nonlinear top-to-bottom thermal gradient. These calculations were done by hand and were somewhat simplified in that they assumed that the thermocouple temperatures measured at the outside of the pipe were representative of the inside fluid temperatures, and did not account for the through-wall thermal gradients. A more accurate thermal stratification stress analysis was done using the SI program TOPBOT.

TOPBOT solves the transient thermal and stress response within a pipe subjected to a step or ramp change in boundary temperatures and heat transfer coefficients. Initial temperature Enclosure 3

conditions are specified, and then a temperature change is applied to either the top or bottom fluid in the pipe, or both. The pipe is considered to be two dimensional at a pipe cross-section (or assumed to be extremely long in the axial direction). Symmetry about the pipe vertical centerline is assumed. The pipe is modeled with rectilinear elements within the R-theta coordinate system. Stresses and temperatures are computed at the center of each element (mean radius and mean angular locations). In addition, temperatures and stresses are computed at the inside and outside surfaces of the pipe, based on the "steady state" temperature distribution between the surface elements and external boundary temperatures.

Required thermal input parameters include thermal conductivity and the product of the density and specific heat, modulus of elasticity, coefficient of thermal expansion, and Poisson's ratio.

The thermal boundary conditions are input as internal and external temperature distributions and heat transfer distributions. For most problems, the initial pipe temperature is uniform: a uniform temperature and heat transfer coefficient is specified on the outside of the pipe, and two sets of temperature and heat transfer coefficients are specified inside the pipe, representing the top and bottom temperatures and flow rates. These two sets of temperatures, heat transfer coefficients, and their interface level can be varied linearly by specifying different values at specific points in time. The pipe temperature distribution is determined using a classical finite difference method. An energy balance is written for each element of the model.

For this analysis, the maximum top-to-bottom temperature distribution was modeled. The stress results were scaled for smaller thermal gradients. The outside pipe temperature at the top, midlevel and bottom of the pipe were observed. In order to determine accurate thermal stratification stresses, the inside fluid temperatures that produce the temperature distribution measured at the outside of the pipe was determined. This required some trial and error, as it is a function of the hot-cold fluid interface level and the convective heat transfer coefficients at the top and bottom inside surface of the pipe; these coefficients in turn depend on the flow rates and temperatures of the fluid levels.

The inside surface forced convection heat transfer coefficients were determined using the following relation for turbulent flow:

h = 0.023 Re0.8 Pr0.4 k / D Where Re = Reynolds number = nVD/ > 4000 for turbulent flow Pr = Prandtl number = cpk k = thermal conductivity, BTU-hr-ft/0F D = hydraulic diameter = 4A/P A = flow area P = flow perimeter V = flow velocity, ftlsec n = density, Ibm/ft3

= dynamic viscosity, lbm /ft-sec cp = specific heat at constant pressure After trial and error, the outside pipe temperature distribution was replicated if the inside fluid temperature were 530°F at the top (some heat loss from RCS cold leg temperature) and 100°F at the bottom (containment ambient temperature), the interface level was at 148° from the top of the pipe, and the top fluid velocity was 0.516 ft/sec, or 3.1 gpm (bypass flow circulation) and the bottom fluid velocity was 0.19 ft/sec, or 0.3 gpm (leakage past auxiliary spray control valve). The actual valve leakage and the other Enclosure 3

parameters may be a little different, but as long as the temperature distribution is established in the analytical model, the stress results were considered to be representative.

Thermal Stratification Analysis Results The results of the TOPBOT thermal stratification analysis were the following:

Fixed End Moment: 108.19 in-kip (for a 300°F top-to-bottom thermal gradient)

Local Stress (maximum location): 40.31 ksi (for a 300°F top-to-bottom thermal gradient)

= 134.37 psi/°F Stress Combinations and Fatigue Usage The stress and fatigue usage were computed at the limiting location, node point 210. This location is classified as ASME Code Class 2. ASME Section III, subsection NC-3600, does not provide explicit fatigue usage criteria; however, the approach used by Markl in his fatigue testing of piping components was used, which has been implicitly adopted in NC-3600:

i S (N)0.2 = 280,000 Where S = stress range, psi i = stress intensification factor = 1.0 at node point 210 (straight pipe)

N = number of allowable full range stress cycles at stress S The stress is the total of the contributions from thermal expansion moments, global thermal stratification, and local thermal stratification.

The thermal expansion moment stress at node 210 was (32113 - 6960) = 25,153 psi.

The global thermal stratification stress calculated was 6960 psi. This stress was obtained by applying the stratification fixed end moment to the piping model. A more accurate fixed end moment was calculated by TOPBOT as described above. The stresses are therefore adjusted by the ratio of the fixed end moments, Global stratification stress = 6960 (108.19/104.34) = 7,217 psi Per the S&L analysis, the magnitude of stratification at point 210 is 0.93 of that measured at the instrumented point. The local stress is

= 134.37 psi/°F (300) (.93) = 37,489 psi.

The stress cycles are grouped in the following manner:

2. 1x140=140 cycles of 455°F thermal expansion moment range + 300°F global stratification +

300°F local stratification

4. 2x140=280 cycles of 150°F thermal expansion moment range + 300°F global stratification +

300°F local stratification Enclosure 3

6. 1x140=140 cycles of 150°F thermal expansion moment range + 230°F global stratification +

230°F local stratification

8. 16x140=2240 cycles of 230°F global stratification + 230°F local stratification

10. 11x140=1540 cycles of 110°F global stratification + 110°F local stratification The thermal expansion moment stress is scaled according to the temperature range of the cycle. For example, for a 150°F range, the thermal expansion range is

= 25,153 (150/455) = 8,292 psi.

The stratification stresses, global and local, are scaled according to the top-to-bottom gradient.

Thus for a 230°F gradient, the global stratification stress is

= 7,217 (230/300) = 5,533 psi and the local stratification stress is

= 37,489 (230/300) = 28,742 psi.

The number of stress cycles for groups 2-5 are then converted into an equivalent number of full range stress cycles using equation (2) in paragraph NC-3611.2 (e) (3) of the ASME B&PV Code. This relationship was developed by Markl in his fatigue testing of piping components and has been incorporated into the ASME Class 2/3 piping Code:

N = N1 + (S2/S1)5 N2 + (S3/S1)5 N3 + (S4/S1)5 N4 + (S5/S1)5 N5 Thus, following this approach, 280 cycles of group 2 are equivalent to 70.36 full range cycles, for example. The total equivalent full range cycles of all five groups is 287. Using Markls equation, the allowable number of cycles at a stress of 69,659 psi is 1,034. Therefore, the total fatigue usage is 0.277 (287/1,034).

Conclusions The result of the stress and fatigue analysis is that for the limiting location on the Unit 1 pressurizer spray line, the calculated fatigue usage for a 60-year plant design life is 0.277. This is well below the allowable of 1.0. The stresses conservatively assume that a significant amount of leakage past the auxiliary spray control valve continues to exist. Thus the stress and fatigue usage for this line is acceptable for a 60-year design life.

NRC Question RAI- 4.3.10.1:

Environmental Effects on Fatigue For the USAS B31.1 locations, provide a description of the PBNP-specific simplified ASME Section III fatigue analyses that were used to calculate environmentally based cumulative usage factors.

NMC Response:

Enclosure 3

Charging Nozzle This location was analyzed using actual plant data and the projected number of cycles in the charging nozzle model included in a FatiguePro application for PBNP and the tensile strain-integrated Fen factor.

The PBNP design basis includes several design transients that affect the charging nozzles.

The most severe of these events is the loss of charging and loss of letdown with delayed return to service. Examination of actual PBNP Units 1 and 2 plant data since 1994 revealed one actual event that accurately represents this design transient. This event was used to represent a bounding loss of charging/loss of letdown event.

Normal fatigue usage for this event was computed. An environmental correction factor (Fen) was then determined to account for environmental effects. The resulting total usage was applied over the expected number of occurrences for this event (17 loss of charging and loss of letdown events projected for the 60-year operating life of each units). The incremental fatigue usage attributed to the loss of charging/loss of letdown event was determined to be 0.00695.

The bounding transient is depicted in the followinf figure.

Enclosure 3

Transient Instrument Values and Stress for Bounding Transient Enclosure 3

Using These Results, the 60-year Projection for this Events (No Envronmental Effects) Is:

Cuf = (17 Events) * (0.00695 per Event) = 0.11815 Environmental Effects - Fen Approach The Fatigue Usage Analysis above Does Not Consider Environmental Effects on the Fatigue Curve. An Environmental Fatigue Factor (Fen) Will Be Determined Based on the Equations Provided in Nureg/cr-5704. Using this Methodology, the Fen Factor Is Computed as a Function of Three Parameters Using the Following Equation:

Fen = Exp (0.935 - T* * Ådot*

• O*)

Where:

T* = 0 T < 200c T* = 1 T ? 200c

Ådot* = 0 Ådot > 0.4%/sec

Ådot* = Ln (Ådot/0.4) 0.0004 ? Ådot ? 0.4%/sec

Ådot* = Ln (0.0004/0.4) Ådot ? 0.0004%/sec O* = 0.260 Do < 0.05 Ppm O* = 0.172 Do ? 0.05 Ppm For this Transient, the Factors Are:

• Strain Range - over the Tensile Portions of the Plant Transient

• Strain Rate - Computed over the Range of Tensile Strain Range

• Temperature - Conservatively Assumed to Be Greater than 200c

• Dissolved Oxygen - Conservatively Assumed to Be less than 0.05 Ppm Individual Fen Values Were Integrated over the Tensile Strain Range of the Transient Stress Cycle(s) Being Analyzed. For the Purpose of Determining Strain Rate, the Stress Changes for Each Time Step with Increasing Stress Were Converted to Strain by Dividing by the Modulus of Elasticity for Stainless Steel (28.3 X 103 Ksi) from the Asme Fatigue Curve. The Strain Difference Was Divided by the Length of the Time Step, Then Converted into Units of [%

Strain/sec].

For Each Time Step, Incremental Fen Was Computed Using the Equation Shown Above. An Effective Fen for the Entire Transient Was Computed by Integrating Fenk for Each Time Step with the Strain Step Associated with That Time Step over the Entire Tensile Strain Range. The Effective Fen Was Computed to Be 6.994.

The Environmentally-assisted Fatigue Projected to 60 Years of Operation Is Thus:

Cufeaf = 0.11815

• 6.994 = 0.8264 Enclosure 3

Safety Injection Nozzle and Rhr Tee These Two Locations Were Analyzed Using Design Transients and the Design Number of Cycles in a Combined Asme Code Section Iii Nb-3600 Class 1 Plant-specific Piping Model of the Safety Injection (Si) Piping System and Rhr System.

The Si Piping, Including the Rhr Tee, Was Modeled Using the Computer Program, Pipestress.

To Perform an Asme Section Iii Class 1 Piping Fatigue Analysis with Pipestress, Thermal Transients and Thermal Expansion Cases Were Defined.

To Evaluate the Fatigue Usage with Pipestress, the Thermal Expansion Cases Correspond to the Final Temperature of Each Analyzed Transient plus the Steady State Operating Case.

Typically, the Governing Contribution to Fatigue Usage Is from Thermal Stresses, Not Pressure Stresses. Thus, the Pressure for Each Case Will Be the Operating Pressure. Use of the Operating Pressure Is Conservative When Used to Calculate Pressure Stresses. This Will Also Be Conservative When Used in the Fatigue Evaluation.

Modes of Operation Were Defined. The Forces and Moments Due to Differential Thermal Expansion as Analyzed by the Piping Program, Pipestress, Were Included in the Fatigue Evaluation.

The Number of Design Transients That Will Occur Through the End of the Extended Operation (60 Years) Were Assumed to Be less than or Equal to the Design Limit (40 Years) for Each Design Transient. Seismic Loading and Thermal Anchor Movements Were Considered for Fatigue Analysis.

The Results of the Fatigue Evaluation Show That the Fatigue Usage at the Si to Cold Leg Branch Connection (Si Nozzle) Is 0.0013 and the Tee from the Rhr to the Si (Rhr Tee) Is 0.0146. Application of the Maximum Possible Fen of 15.35 Produced Environmentally Assisted Fatigue Usage Values of 0.02 and 0.224, for the Si Nozzle and Rhr Tee, Respectively.

NRC Question RAI- 4.3.10.2:

Environmental Effects on Fatigue The Pressurizer Cufs Are Determined Based on Epri Mrp-47 Methodology. The Staff Has Not Endorsed Mrp-47. Provide the Environmentally Assisted Cufs for the Pressurizer Locations, Based on the Staff-accepted Methodology as Stated in Sections 4.3.2.2 and 4.3.3.2 of Nureg-1800.

NMC Response:

The pressurizer components were evaluated for environmental effects on fatigue per the direction of Applicant Action Item 3.3.1.1-1 of the NRC SER of Westinghouse GTR WCAP-14574-A. Applicant Action Item 3.3.1.1-1 of the NRC SER of Westinghouse GTR WCAP-14574-A does not specify a requisite method for addressing the environmental effects on fatigue. NUREG-1800 does not require that pressurizer components be evaluated for environmental effects on fatigue.

Sections 4.3.2.2 and 4.3.3.2 of NUREG-1800 note that formulas for calculating the environmental life correction factors for carbon and low-alloy steels are contained in NUREG/CR-6583 and those for austenitic SSs are contained in NUREG/CR-5704.

Enclosure 3

Application of the NUREG/CR-6583 and 5704 formulas for calculating the environmental life correction factors for the PBNP pressurizers, verses the EPRI MRP-47 Appendix B formulas will not have an overly significant impact on the pressurizer components evaluations. This is because the EPRI MRP-47 Z factor was not used in the evaluations, the evaluation temperature of 345 degrees centigrade results in the stainless steel formulas being identical between the two methods, and the carbon or low alloy steel formulas were not applied since the dissolved oxygen (DO) values were well below the threshold values.

The environmentally adjusted fatigue (EAF) CUF for the spray nozzle safe end is not affected since this location is stainless steel and the formulas are identical in the analyzed temperature range.

The 60-year EAF CUF for the surge nozzle safe end is not affected since this location is stainless steel and the formulas are identical in the analyzed temperature range.

The 60-year EAF CUF for the limiting carbon steel portion of the surge nozzle was noted to be the same as the design basis value since the DO level is well below the threshold level. Using the NUREG/CR-6583 formula, the design basis value would be multiplied by a Fen of 1.17 as a result of the temperature, regardless of the low DO level. The resulting 60-year EAF CUF would be 0.73, which is acceptable since it is less than 1.0.

The 60-year EAF CUF for the carbon steel / low alloy steel junction of the upper head and shell was noted to be the same as the design basis value since the DO level is well below the threshold level. Using the NUREG/CR-6583 formula, the design basis value would be multiplied by a Fen of 1.65 as a result of the temperature, regardless of the low DO level. The resulting 60-year EAF CUF would be 1.28. Since the evaluation for the carbon steel / low alloy steel junction of the upper head and shell is based on the design transient set, the results of the evaluation are extremely conservative in both the severity and numbers of transients. Significant reductions in the estimates are possible if adjustments are made to remove the operational transients that are not experienced / practiced at PBNP. The EPRI FatiguePro software program was customized to monitor the carbon steel / low alloy steel junction of the upper head and shell at PBNP. An analysis was performed based on available template sets of real plant data to determine the incremental fatigue usage factor for known plant transients. A cumulative usage factor for the operating life of the plant was computed based on the results of real plant data, and expected future usage was computed using projections of expected plant cycles. The 60-year CUF for the Unit 1 pressurizers carbon steel / low alloy steel junction of the upper head and shell bounds the 2 units, and is projected to be 0.156. Applying the maximum environmental fatigue correction factor of 2.53 to the projected CUF of the carbon steel / low alloy steel junction of the upper head and shell location, results in a conservative 60-year EAF CUF of 0.39. This demonstrates adequate structural integrity, including the effects of environmental conditions, for a projected 60-year operational period.

The 60-year EAF CUF for the safety and relief nozzle safe ends was noted to be the same as the design basis value since the CUF of these components is zero.

The 60-year EAF CUF for the limiting carbon steel portion of the safety and relief nozzle was noted to be the same as the design basis value since the DO level is well below the threshold level. Using the NUREG/CR-6583 formula, the design basis value would be multiplied by a Fen of 1.17 as a result of the temperature, regardless of the low DO level. The resulting 60-year EAF CUF would be 0.174, which is acceptable since it is less than 1.0.

Enclosure 3

The environmentally adjusted fatigue (EAF) CUF for the instrument nozzle is not affected since this location is stainless steel and the formulas are identical in the analyzed temperature range.

The environmentally adjusted fatigue (EAF) CUF for the heater well is not affected since this location is stainless steel and the formulas are identical in the analyzed temperature range.

Enclosure 3