BSEP 05-0050, Response to Request for Additional Information - License Renewal

Response to Request for Additional Information - License Renewal

ML051330020
Person / Time
Site:	Brunswick
Issue date:	05/04/2005
From:	Gannon C Progress Energy Co
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
BSEP 05-0050, TAC MC4639, TAC MC4640
Download: ML051330020 (95)

Text

Cornelius J. Gannon Progress Energy Vice President Brunswick Nuclear Plant Progress Energy Carolinas, Inc.

May 4, 2005 SERIAL: BSEP 05-0050 10 CFR 54 U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001

Subject:

Brunswick Steam Electric Plant, Unit Nos. I and 2 Docket Nos. 50-325 and 50-324/License Nos. DPR-71 and DPR-62 Response to Request for Additional Information - License Renewal (NRC TAC Nos. MC4639 and MC4640)

References:

1. Letter from Cornelius J. Gannon to the U. S. Nuclear Regulatory Commission (Serial: BSEP 04-0006), "Application for Renewal of Operating Licenses," dated October 18, 2004 (ML043060406)

2. Letter from Sikhindra K. Mitra, to Cornelius J. Gannon, "Request for Additional Information for the Review of the Brunswick Steam Electric Plant, Units 1 and 2, License Renewal Application," dated April 8, 2005 (ML050980244)

3. Letter from Cornelius J. Gannon to the U. S. Nuclear Regulatory Commission (Serial: BSEP 05-0041), "Response to Audit Questions License Renewal NUREG-1801 Consistency Audit," dated March 14, 2005 (ML050810491)

Ladies and Gentlemen:

On October 18, 2004, Carolina Power & Light Company, now doing business as Progress Energy Carolinas, Inc. (PEC), requested the renewal of the operating licenses for Brunswick Steam Electric Plant (BSEP), Unit Nos. 1 and 2, to extend the terms of their operating licenses an additional 20 years beyond the current expiration dates.

By letter dated April 8, 2005, the Nuclear Regulatory Commission (NRC) provided a request for additional information (RAI) concerning the BSEP License Renewal Application. to this letter provides responses to the NRC RAI. Also, provided in Enclosure 1 is supplemental information in response to NRC Audit Question B.2.15-1; the previous response had been provided in PEC's letter dated March 14, 2005.

P.O.

Box 10429 Southport, NC 28461 T> 910.457.3698 F> 910.457.2803

Document Control Desk BSEP 05-0050 / Page 2 is the summary list of regulatory commitments supporting License Renewal, modified to reflect the information provided in the RAI responses.

Please refer any questions regarding this submittal to Mr. Mike Heath, Supervisor - License Renewal, at (910) 457-3487.

I declare, under penalty of perjury, that the foregoing is true and correct. Executed on May 4, 2005.

Sincerely, Gannon MHF/mhf

Enclosures:

1. Responses to Request for Additional Information, dated April 8, 2005, and Supplemental Response to Audit Question B.2.15-1

2. BSEP License Renewal Commitments, Revision 3

Document Control Desk BSEP 05-0050 / Page 3 cc:

U. S. Nuclear Regulatory Commission, Region II ATIN: Dr. William D. Travers, Regional Administrator Sam Nunn Atlanta Federal Center 61 Forsyth Street, SW, Suite 23T85 Atlanta, GA 30303-8931 U. S. Nuclear Regulatory Commission ATTN: Mr. S. K. Mitra (Mail Stop OWFN 11F1) 11555 Rockville Pike Rockville, MD 20852-2738 U. S. Nuclear Regulatory Commission ATITN: Mr. Richard L. Emch (Mail Stop OWFN 11F1) 11555 Rockville Pike Rockville, MD 20852-2738 U. S. Nuclear Regulatory Commission ATIN: Mr. Eugene M. DiPaolo, NRC Senior Resident Inspector 8470 River Road Southport, NC 28461-8869 U. S. Nuclear Regulatory Commission (Electronic Copy Only)

ATTN: Ms. Brenda L. Mozafari (Mail Stop OWFN 8G9) 11555 Rockville Pike Rockville, MD 20852-2738 Ms. Jo A. Sanford Chair - North Carolina Utilities Commission P.O. Box 29510 Raleigh, NC 27626-0510

BSEP 05-0050 Page 1 of 87 Responses to Request for Additional Information dated April 8, 2005, and Supplemental Response to NRC Audit Question B.2.15-1

Background

On October 18, 2004, Carolina Power & Light Company (CP&L), now doing business as Progress Energy Carolinas, Inc. (PEC), submitted a License Renewal Application (LRA) that requested the renewal of the operating licenses for Brunswick Steam Electric Plant (BSEP), Unit Nos. I and 2, to extend the terms of their operating licenses an additional 20 years beyond the current expiration dates.

By letter dated April 8, 2005, the Nuclear Regulatory Commission (NRC) provided a request for additional information (RAI) concerning the LRA. Responses to the RAI are provided in this enclosure. Also, provided in this enclosure is supplemental information in response to NRC Audit Question B.2.15-1; the previous response had been provided in PEC's letter dated March 14,2005.

Table of Contents Page Table of Acronyms and Abbreviations..........................

4 NRC RAI 2.1-1...........................

6 NRC RAI 2.1-2...........................

8 NRC RAI 2.3.1.1-1..........................

10 NRC RAI 2.3.1.1-2..........................

10 NRC RAI 2.3.1.1-3..........................

10 NRC RAI 2.3.1.1-4..........................

11 NRC RAI 2.3.1.1-5..........................

12 NRC RAI 2.3.1.1-6..........................

13 NRC RAI 2.3.1.1-7..........................

13 NRC RAI 2.3.2.1-1..........................

14 NRC RAI 2.3.3.1-1..........................

14 NRC RAI 2.3.3.1-2..........................

15 NRC RAI 2.3.3.1-3..........................

16 NRC RAI 2.3.3.1-4..........................

17 NRC RAI 2.3.3.3-1..........................

17 NRC RAI 2.3.3.4-1..........................

18 NRC RAI 2.3.3.6-1..........................

19 NRC RAI 2.3.3.7-1..........................

20 NRC RAI 2.3.3.7-2a..........................

20 NRC RAI 2.3.3.7-2b..........................

20 NRC RAI 2.3.3.7-3a..........................

21 NRC RAI 2.3.3.7-3b..........................

21 NRC RAI 2.3.3.7-4a..........................

22 NRC RAI 2.3.3.7-4b..........................

22

BSEP 05-0050 Page 2 of 87 NRC RAI 2.3.3.7-5a..............

23 NRC RAI 2.3.3.7-5b.............

23 NRC RAI 2.3.3.7-6a.............

24 NRC RAI 2.3.3.7-6b..............

24 NRC RAI 2.3.3.7-7a..............

25 NRC RAI 2.3.3.7-7b.............

26 NRC RAI 2.3.3.7-8a..............

26 NRC RAI 2.3.3.7-8b..............

27 NRC RAI 2.3.3.7-9a..............

27 NRC RAI 2.3.3.7-9b.............

27 NRC RAI 2.3.3.8-1.............

28 NRC RAI 2.3.3.8-2.............

29 NRC RAI 2.3.3.10-1.............

29 NRC RAI 2.3.3.10-2.............

30 NRC RAI 2.3.3.10-3..............

31 NRC RAI 2.3.3.10-4.............

32 NRC RAI 2.3.3.10-5.............

32 NRC RAI 2.3.3.12-1.............

33 NRC RAI 2.3.3.12-2..............

34 NRC RAI 2.3.3.14-1.............

34 NRC RAI 2.3.3.14-2.............

35 NRC RAI 2.3.3.14-3..............

36 NRC RAI 2.3.3.15-1.............

36 NRC RAI 2.3.3.15-2..............

37 NRC RAI 2.3.3.15-3..............

37 NRC RAI 2.3.3.15-4.............

38 NRC RAI 2.3.3.15-5.............

38 NRC RAI 2.3.3.15-6..............

39 NRC RAI 2.3.3.15-7.............

39 NRC RAI 2.3.3.17-1..............

40 NRC RAI 2.3.3.17-2.............

41 NRC RAI 2.3.3.17-3.............

41 NRC RAI 2.3.3.18-1.............

42 NRC RAI 2.3.3.18-2..............

43 NRC RAI 2.3.3.18-3.............

44 NRC RAI 2.3.3.19-1.............

45 NRC RAI 2.3.3.19-2..............

46 NRC RAI 2.3.3.24-1.............

47 NRC RAI 2.3.3.26-1.............

48 NRC RAI 2.3.3.33-1.............

49 NRC RAI 2.3.4.5-1.............

50 NRC RAI 2.3.4.7-1..............

51 NRC RAI 2.3.4.11-1..............

51 NRC RAI 3.2-1.............

52 NRC RAI 3.2-2.............

53 NRC RAI 3.2-3.............

54

BSEP 05-0050 Page 3 of 87 NRC RAI 3.2-4........................................

54 NRC RAI 3.2-5.........................................

55 NRC RAI 3.2-6.........................................

56 NRC RAI 3.2-7........................................

56 NRC RAI 3.4-1........................................

57 NRC RAI 3.4-2........................................

57 NRC RAI 3.4-3........................................

58 NRC RAI 3.4-4........................................

59 NRC RAI 3.5-1........................................

59 NRC RAI 3.5-2........................................

60 NRC RAI 3.5-3.........................................

61 NRC RAI 3.5-4........................................

61 NRC RAI 3.5-5........................................

62 NRC RAI 3.5-6.........................................

62 NRC RAI 3.5-7........................................

63 NRC RAI 3.5-8........................................

63 NRC RAI 3.5-9..........................................

64 NRC RAI 3.5-10.........................................

65 NRC RAI 3.5-11........................................

66 NRC RAI 4.2-1........................................

67 NRC RAI 4.2-2.........................................

68 NRC RAI 4.2.4-1........................................

70 NRC RAI 4.2.5-1.........................................

70 NRC RAI 4.2.5-2........................................

71 NRC RAI 4.2.6-1........................................

73 NRC RAI 4.2.7-1.........................................

74 NRC RAI 4.2.8-1.........................................

75 NRC RAI 4.2.8-2........................................

77 NRC RAI 4.2.9-1........................................

79 NRC RAI 4.3-1........................................

80 NRC RAI 4.3-2........................................

80 NRC RAI 4.6-1.........................................

8 1 NRC RAI 4.6-2........................................

82 NRC RAI 4.6.1-1........................................

82 NRC RAI 4.6.1-2........................................

84 NRC Audit Question B.2.15-la (Supplemental Response)........................................

85

BSEP 05-0050 Page 4 of 87 The following table contains the acronyms and abbreviations used in this enclosure.

TABLE OF ACRONYMS AND ABBREVIATIONS AP Delta-P. i.e., Differential Pressure AEC Atomic Energy Commission AFFF Aqueous Film Forming Foam AMP Aging Management Program AMR Aging Management Review ANSI American National Standards Institute ART Adjusted Reference Temperature ASME American Society of Mechanical Engineers BSEP Brunswick Steam Electric Plant BWR Boiling Water Reactor BWROG Boiling Water Reactor Owners Group BWRVIP Boiling Water Reactor Vessel and Internals Program CB&I Chicago Bridge & Iron Works CE Combustion Engineering CLB Current Licensing Basis CP&L Carolina Power & Light Company CRD Control Rod Drive CRDH Control Rod Drive Housing CRW Clean Radwaste CST Condensate Storage Tank CTL Commitment Tracking List CUF Cumulative Usage Factor CW Circulating Water DBD Design Basis Document DG Diesel Generator DRW Dirty Radwaste DTOP Design Turnover Project EDB Equipment Database EFPY Effective Full Power Years EPRI Electric Power Research Institute EPUR Extended Power Uprate EQ Environmental Qualification FSAR Final Safety Analysis Report GALL Generic Aging Lessons Learned (the GALL Report is NUREG-1801)

GE General Electric HPCI High Pressure Coolant Injection IA Instrument Air IFI (NRC) Inspection Follow-up Item IN (NRC) Information Notice ISG Interim (NRC) Staff Guidance ISI In-Service Inspection LCO Limiting Condition for Operation LOCA Loss of Coolant Accident LPCI Low Pressure Coolant Injection LO Lube Oil LR License Renewal LRA License Renewal Application MeV Million Electron Volts MTEB Materials Engineering Branch (former NRC Division of Engineering Branch)

BSEP 05-0050 Page 5 of 87 TABLE OFACRONYMS AND ABBREVIATIONS MWT Makeup Water Treatment NDTT Nil-Ductility Transition Temperature NDE Nondestructive Examination NEI Nuclear Energy Institute NFPA National Fire Protection Association NPS Nominal Pipe Size NRC Nuclear Regulatory Commission NUREG Designation of publications prepared by the NRC staff P&ID Piping and Instrumentation Diagram PEC Progress Energy Carolinas PM Preventive Maintenance PNS Pneumatic Nitrogen System P-T Pressure - Temperature QA Quality Assurance RAI Request for Additional Information RBCCW Reactor Building Closed Cooling Water RCIC Reactor Core Isolation Cooling RCPB Reactor Coolant Pressure Boundary RG Regulatory Guide RHR Residual Heat Removal RHX Regenerative Heat Exchanger RI-ISI Risk-Informed Inservice Inspection RPV Reactor Pressure Vessel RTNDT Reference Temperature for Nil-Ductility Transition RV Reactor Vessel RWCU Reactor Water Cleanup System RXS Reactor Building Sampling System SBO Station Blackout SC Structure and/or Component SCC Stress Corrosion Cracking SE Safety Evaluation SER Safety Evaluation Report SGT Standby Gas Treatment SLC Standby Liquid Control SRP-LR Standard Review Plan for License Renewal SRV Safety/Relief Valve SSC Systems, Structures, and Components SCW Screen Wash Water SW Service Water TLAA Time-Limited Aging Analysis UFSAR Updated Final Safety Analysis Report USAS United States of America Standards USE Upper Shelf Energy

BSEP 05-0050 Page 6 of 87 NRC RAI 2.1-1 During the Brunswick scoping and screening methodology audit, the staff determined that the applicant had performed component based scoping and had included SCs within the scope of license renewal based upon the SC's classification within the Equipment Data Base relative to the criteria of 10 CFR 54.4(a)(1), (2), or (3). The applicant had then included all systems within the scope of license renewal which contained any SCs which had been determined to be in-scope based on the SC's classification within the Equipment Data Base. The applicant indicated that the in-scope system CLB documentation, including the system intended functions, had been reviewed to verify that all in-scope SC's had been identified.

The staff reviewed the information contained in the LRA, discussed the process with the applicant and reviewed the applicable process implementation guidance. The staff determined that the process by which the current licensing basis information, including system intended functions, had been reviewed and considered during the scoping process was not clearly documented in the LRA. As a result, the staff requests that the applicant document how the current licensing basis information, including system intended functions, was considered during the scoping process.

RAI 2.1-1 Response In addition to the scoping of systems, structures, and components (SSC) based on quality classifications of individual structures and components (SCs) in the Equipment Database (EDB),

the BSEP scoping process included a review of the following types of plant and current licensing basis (CLB) documents to the extent required to develop the descriptive material, including system intended functions, for use in the LRA:

• The Updated Final Safety Analysis Report (UFSAR),

• Design Basis Documents (DBDs),

• System Descriptions,

• Docketed Correspondence (especially used for the scoping of 10 CFR 54.4(a)(3) systems),

• PassPort EDB, and

• Maintenance Rule Database.

The review was performed to document the SSC descriptions and functions to be incorporated into the SSC Scoping Worksheets, and ultimately into Sections 2.3 and 2.4 of the LRA, so that the description of each SSC and its functions were available for review.

It should be noted that the methodology through which SCs are assigned a quality classification within the EDB also involves a procedurally-controlled process that considers the intended functions of the parent SSC as documented in CLB documents. The use, revision, and control of equipment information in the EDB are governed by PEC corporate and BSEP procedures. These

BSEP 05-0050 Page 7 of 87 procedures establish the EDB as a design document and require that certain data fields containing design information, including quality classification, be changed only by use of the Engineering Change process. The Engineering Change process implements the Quality Assurance (QA) Program requirements for design control and assures that revisions to the information in the EDB are verified and that changes to the plant design and licensing bases, initiated through plant modifications, are captured in EDB.

The BSEP Q-List was developed in response to NRC QA guidelines that were ultimately published in 1970 as Appendix B to 10 CFR Part 50. The Q-List consisted of the equipment, materials, systems, and structures subject to QA Program requirements, because of their function in preventing nuclear accidents having the potential of causing injury to the public from substantial levels of radiation or release of substantial quantities of radioactive materials from their intended place of confinement within the plant, or mitigating the consequences of such accidents. The Q-List was incorporated into Appendix D of the original BSEP Final Safety Analysis Report (FSAR). Further clarification of the list was provided in response to NRC comment D.6, included in FSAR Amendment 15, dated March 1973.

The EDB was developed in response to NRC Generic Letter 83-28 in order to upgrade the Q-List program at BSEP to create a more detailed, component-level quality classification system for plant equipment. Refer to letter from P. W. Howe to D. G Eisenhut (USNRC), (Serial:

LAP-83-513) "Generic Implications of Salem ATWS Event," dated November 7, 1983, for additional information.. The intent was to assure that subcomponents of Q-List equipment received the proper attention under the QA Program. Q-List equipment, and consequently EDB components, were identified by means of a functional review at the system or structure level.

The Q-List for BSEP was developed to meet the requirements of 10 CFR 50, Appendix B, which include, among other things, that an applicant shall identify the structures, systems, and components to be covered by the quality assurance program. The introduction to Appendix B states that the equipment to be included in a QA Program are structures, systems, and components that prevent or mitigate the consequences of postulated accidents that could cause undue risk to the health and safety of the public. Procedures were developed to manage the incorporation and revision of the controlled data stored in the EDB, such as, quality classification, seismic Category I requirements, and Environmental Qualification (EQ) requirements. Procedures also were developed to manage the review of components within SSCs, to determine their function in support of the overall system-level functions of the parent SSC. For example, the review of safety related components involved the identification of SSCs that performed safety related functions as defined in 10 CFR Part 21, 10 CFR Part 100, and 10 CFR 50.49. The current BSEP procedure for classification of components in EDB continues to apply a process that begins with the established intended functions performed by the parent system or structure.

During the License Renewal review, information from the EDB was evaluated to determine its suitability for use in the scoping process defined in 10 CFR 54.4. A License Renewal calculation was developed to document the evaluation. The review determined that EDB quality classifications could be used to facilitate identification of SSCs within scope and provide an indication of the intended functions that the SSCs perform. The License Renewal calculation identified several components that were classified safety related in EDB but did not meet the

BSEP 05-0050 Enclosure I Page 8 of 87 requirements of 10 CFR 54.4 for scoping of SSCs. These were addressed in an attachment to the License Renewal calculation, and the bases for not including them in scope for License Renewal were documented. For example, the Spent Fuel Shipping Cask was identified in EDB as safety related; however, it was licensed in accordance with 10 CFR Part 71 requirements and, therefore, is not in scope of License Renewal.

The process used for scoping continually checked EDB component results against other sources.

The EDB function descriptions were compared with UFSAR and DBD function description. In addition, component level scoping results were mapped to system drawings. Untagged commodities were identified based on the drawing review. Component mapping on the drawings afforded an effective check to ensure that the functions described in the CLB documents were consistent with EDB information. The overall process identified some EDB discrepancies that were subsequently resolved in accordance with the BSEP Corrective Action Program.

NRC RAI 2.1-2 Based on a review of the LRA, the applicant's scoping and screening implementation procedures, calculations, and discussions with the applicant, the staff determined that additional information is required with respect to certain aspects of the applicant's evaluation of the 10 CFR 54.4(a)(2) criteria.

Section 2.1.1.2, "Non-Safety Related Criteria Pursuant to 10 CFR 54.4(a)(2)," of the LRA, and several of the applicant's calculations prepared to address the (a)(2) issue, state that nonsafety related piping that is attached to safety related piping, and that is seismically designed and supported up to the first seismic anchor (emphasis added) past the safety related/nonsafety related interface, should be included within the scope of license renewal. The LRA also states that the analysis of seismic induced effects was continued wvell into (emphasis added) the non-safety related piping in order to include the effects that non-safety related piping has on the adjoining safety related piping.

Based on the above, the staff requests that the applicant confirm that the first seismic anchor occurs at the point where non-safety related piping is restrained in three directions, or if not practical, supported in three directions by three individual supports; confirm that this approach is consistent with the CLB position for seismic-induced effects between connected non-safety related and safety related piping documented in Amendment 15 of the BSEP FSAR; and describe the methodology of its application.

RAI 2.1-2 Response Amendment 15 of the BSEP original FSAR documents the following question as to the effects of Seismic Category II piping systems on Seismic Category I piping systems. The following is the NRC question and the BSEP response:

BSEP 05-0050 Page 9 of 87 Comment C.54 Describe the evaluation performed to determine seismic induced effects of Category II piping systems on Category I piping.

Response

In cases where Category I piping and Category II piping are connected, the analysis was continued well into the Category II piping in order to include the effects that Category II piping has on the adjoining Category I piping.

Generally, this continuation was to a point where the Category H pipe was restrained in three (3) directions. If this was not practical, the Category II pipe was analyzed up to a point in the system where it was supported in three (3) directions by three (3) individual supports.

BSEP implemented the Design Turnover Project (DTOP) to disposition nonconformance S-86-021, issued March 28, 1986, titled, "Seismic Supports Have Discrepancies Between Installed Configuration and As-Built Drawings." As part of this effort, the BSEP architect/engineer provided study reports to document pipe stress analysis methodology. One of these study reports specifically addressed Seismic Class I boundary conditions and incorporated the response to Comment C.54 by reference.

The NRC staff tracked completion of the Design Turnover Project under Inspection Follow-up Item (IFI) 325,324/94-17-01, which was closed in May 1995. Refer to letter from C.A. Casto, (NRC), to R.A. Anderson, "NRC Inspection Report No. 50-325/95-08 and 50-324/95-08," dated May 26, 1995, for further information.

Corporate procedures for the performance of pipe stress analysis have incorporated the aforementioned study report by reference. The incorporation of Comment C.54 into the design control documents at BSEP ensures that the CLB requirements are met.

The methodology employed to validate that all seismically-connected piping per NRC Interim Staff Guidance (ISG)-9 was properly evaluated for inclusion within the scope of License Renewal was multi-faceted. BSEP employed a "spaces" approach for the review of liquid-filled piping systems. Liquid-filled piping located in buildings housing safety related components was brought into the scope of License Renewal unless a specific documented evaluation was performed to exclude a particular space. When this evaluation was complete, a separate evaluation was performed to ensure that the seismically-connected piping, i.e., associated with safety related/non-safety related boundaries, that was not thus far included, was brought within the scope of License Renewal consistent with the CLB.

A separate evaluation was performed for air/gas-filled piping. This evaluation included the following, consistent with the CLB:

• Review of safety related/non-safety related boundaries to determine the extent of non-safety related piping required to protect the interface,

• Review of pipe stress analyses,

BSEP 05-0050 Page 10 of 87

• Review of the UFSAR,

• Review of DBDs, and v

Review of design specifications.

Finally, the License Renewal boundary drawings were reviewed to ensure that there were no anomalous conditions that required further evaluation.

NRC RAI 2.3.1.1-1 In FSAR Section 3.9.5.1.1 it states, the core shroud is reinforced at the upper shroud/top fuel guide support ring/middle shroud interface with twelve (12) brackets located at 30 degree intervals starting at the 15 degree azimuth. These brackets provide structural integrity across the interface and compensate for cracking in the heat affected zones of the original fabrication welds.

Please indicate whether the top fuel guide support ring and middle shroud interface brackets have been included in scope of license renewal orjustify the exclusion of these components.

RAI 2.3.1.1-1 Response These components are in scope. The 12 brackets are evaluated as "Core Shroud and Core Plate (Core Shroud Repair Hardware)" and the subcomponents of the Core Shroud are evaluated as "Core Shroud and Core Plate (Core Shroud (Upper, Central, Lower))" as shown in Table 2.3.1-1 on page 2.3-6 of the LRA.

NRC RAI 2.3.1.1-2 In FSAR Section 3.9.5.1.3 it states, a thermal sleeve is inserted into the control rod drive housing (CRDH) from below and is rotated to lock the control rod guide tube in place. A key is inserted into a locking slot in the bottom of the CRDH to hold the thermal sleeve in position. Please indicate whether the CRDH thermal sleeve is included in scope of license renewal or justify its exclusion.

RAI 2.3.1.1-2 Response This subcomponent is in scope but is below the level of detail presented in the Aging Management Review (AMR) tables. See page 2.3-2 of the LRA - "Control Rod Drive (CRD) equipment." Similar to other subcomponents that comprise the Reactor Vessel Internals, the applicable aging management programs are Water Chemistry and Reactor Vessel and Internals Structural Integrity.

NRC RAI 2.3.1.1-3 Please indicate whether thermal sleeves for recirculation inlet nozzles are considered part of reactor vessel nozzles, nozzles safe ends and/or instrumentation penetrations requiring an aging

BSEP 05-0050 Page 11 of 87 management review (AMR). The subject components represent a pressure boundary and direct flow to core spray spargers and jet pumps.

RAI 2.3.1.1-3 Response The thermal sleeve is evaluated as "Jet Pump Assemblies (Thermal Sleeve)" as shown in Table 2.3.1-1 on page 2.3-6 of the LRA. The associated AMR line items are shown on pages 3.1-58 and 3.1-59 of the LRA. Note: Flow from the Reactor Pressure Vessel (RPV)

Recirculation Inlet Nozzles, i.e., Nozzles N2A through N2K, directs flow only to the Jet Pumps.

Flow to the Core Spray Spargers is through the Core Spray Nozzles, i.e., N5A and N5B.

NRC RAI 2.3.1.1-4 The differential pressure and liquid control line serves a dual function within the reactor vessel:

(1) to inject liquid control solution into the coolant stream and (2) to sense the differential pressure across the core support assembly. Please indicate whether the subject component is considered part of reactor vessel nozzles, nozzles safe ends and/or instrumentation penetrations requiring an AMR.

RAI 2.3.1.1-4 Response The Core Differential Pressure and Standby Liquid Control (SLC) lines within the vessel are not within the scope of License Renewal. On May 15, 1998, the BWR Vessel and Internals Program (BWRVIP) issued "Appendix B, BWR Standby Liquid Control System Core Plate Delta P Inspection and Flaw Evaluation Guideline, Demonstration of Compliance with the Technical Information Requirements of the License Renewal Rule (10 CFR 54.21)." Refer to letter from V. Wagoner, BWRVIP Integration Committee, to C. Carpenter, (USNRC), (Serial: 98-185),

"License Renewal Appendix B to BWR Vessel and Internals Project, BWR Standby Liquid Control System Core Plate Delta P Inspection and Flaw Evaluation Guideline (BWRVIP-27),

April, 1997," dated May 15, 1998, for further information. Section B.2 of Appendix B discusses the components subject to an AMR. Regarding Differential Pressure/Standby Liquid Control (AP/SLC) lines, it states:

The only AP/SLC components required to accomplish the intended function are the vessel penetration/nozzle and SLC external piping. The AP/SLC internals piping is not within the license renewal evaluation boundary because it is not required to accomplish the intended function. Therefore, an aging management review of the internals piping is not needed for license renewal.

In Section 2.1 of the NRC Safety Evaluation (SE) for the License Renewal version of BWRVIP-27, it states:

In Appendix B, the BWRVIP identified the passive and long-lived components as required by 10 CFR 54.21(a)(1). The BWRVIP'noted that the AP/SLC vessel penetration/nozzle and safe-end extensions are subject to aging management review.

BSEP 05-0050 Page 12 of 87 The NRC SE was provided by letter from C. Grimes, (USNRC), to C. Terry, (BWRVIP),

"Acceptance for Referencing of Report, `BWR Vessel and Internals Project, BWR Standby Liquid Control System / Core Plate A P Inspection and Flaw Evaluation Guidelines (BWRVIP-27),' for Compliance with the License Renewal Rule (10 CFR PART 54)," dated December 20, 1999.

In Section 3.1 of the SE, it states:

The staff agrees that the AP/SLC vessel penetration/nozzle and safe-end extensions are subject to aging management review because they perform intended functions without moving parts or without a change in configuration or properties, and are not subject to replacement based on a qualified life or specified time period. The staff concludes that BWR applicants for license renewal must identify the appropriate subject RPV internal components as subject to aging management to meet the applicable requirements of 10 CFR 54.21 (a)(1).

The AP/SLC vessel penetration/nozzle is evaluated as part of "Penetrations (Standby Liquid Control)" and the safe-end is evaluated as "Nozzle Safe Ends (Standby Liquid Control)." These commodities are shown in Table 2.3.1-1 on page 2.3-5 of the LRA. The associated AMR line items appear in Table 3.1.2-1 on pages 3.1-34, 3.1-40, and 3.1-41 of the LRA.

NRC RAI 2.3.1.1-5 The two 100 percent capacity core spray lines separately enter the reactor vessel through the two core spray nozzles. Each line divides immediately inside the reactor vessel. The two halves are routed to opposite sides of the reactor vessel and are supported by clamps attached to the vessel wall. The header halves are then routed downward into the downcomer annulus and pass through the upper shroud immediately below the flange. The flow divides again as it enters the center of the semi-circular sparger ring which is routed halfway around the inside of the upper shroud. The ends of the two sparger rings for each line are supported by slip-fit brackets designed to accommodate thermal expansion of the rings. The header routing and supports are designed to accommodate differential movement between the shroud and the vessel. Please indicate whether the core spray clamps which are attached to the vessel wall and the slip-fit brackets which support the ends of the two sparger rings are included in scope of license renewal requiring an AMR or justify their exclusion.

RAI 2.3.1.1-5 Response The components described are within the scope of License Renewal. The Core Spray Bracket is evaluated as part of "Vessel Shell (Attachment Welds)" as shown in Table 2.3.1-1 on page 2.3-5 of the LRA. The associated AMR line items appear in Table 3.1.2-1 on pages 3.1-22 and 3.1-23 of the LRA. The slip-fit brackets which support the ends of the two sparger rings are evaluated as part of "Core Shroud and Core Plate (Core Shroud (Upper, Central, Lower))" as shown in

BSEP 05-0050 Page 13 of 87 Table 2.3.1-1 on page 2.3-6 of the LRA. The associated AMR line items appear in Table 3.1.2-1 on pages 3.146 and 3.1-47 of the LRA.

NRC RAI 2.3.1.1-6 The staff position on reactor vessel flange leak-off lines is that unless a plant specific justification is provided, the components should be in scope requiring aging management.

Please confirm whether any of the component types listed in LRA Table 2.3.1-1, "Reactor Vessel and Internals," include the subject component. If not, then the subject components should be identified as within scope requiring aging management or provide a plant specific justification for the exclusion.

RAI 2.3.1.1-6 Response The vessel flange leak detection line is within the scope of License Renewal. The vessel flange leak detection line is evaluated as part of "Non-Reactor Coolant Pressure Boundary (Boiling Water Reactor) (Piping and Fittings)" and "Non-Reactor Coolant Pressure Boundary (Boiling Water Reactor) (Valves)" as shown in Table 2.3.1-1 on page 2.3-7 of the LRA. The associated AMR line items appear in Table 3.1.2-1 on pages 3.1-75, 3.1-76, and 3.1-77 of the LRA. The vessel flange leak detection line is discussed in Section 3.1.2.2.4.2 on page 3.1-8 as follows:

The reactor vessel flange leak detection line at BSEP is a Class 2 line that is normally dry.

The BSEPAMR methodology assumed that this stainless steel line is exposed to treated water and, therefore, is susceptible to cracking due to stress corrosion cracking. This aging effect will be managed with a combination of the Water Chemistry Program and the One-Time Inspection Program.

Further, the vessel flange leak detection line is discussed in the context of responding to Applicant Action Item 4 to BWRVIP-74-A on page B-78 of the LRA as follows:

The vessel flange leak detection lines are not part of the reactor coolant pressure boundary and as such are not evaluated against Chapter IV of NUREG-1801. These lines (associated with Nozzle N13) are within the scope of License Renewal and are evaluated with all other non-reactor coolant pressure boundary piping and fittings. The AMR for these lines concluded that these lines are susceptible to cracking and loss of material.

These lines will be managed by the Water Chemistry and One-Time Inspections Programs.

NRC RAI 2.3.1.1-7 At BSEP the steam separators are attached to the top of stand pipes which are welded into the shroud head. Please indicate whether the subject component is included in LRA Table 2.3.1-1 component group "Reactor Vessel Internals (Boiling Water Reactor - Non-safety Related)

(Shroud Head and Separators)."

BSEP 05-0050 Page 14 of 87 RAI 2.3.1.1-7 Response This subcomponent of the Shroud Head and Separators is within the scope of License Renewal and is evaluated as part of "Reactor Vessel Internals (Boiling Water Reactor - Non-safety Related) (Shroud Head and Separators)."

NRC RAI 2.3.2.1-1 The low pressure coolant injection (LPCI) coupling was identified in the BWRVIP-06 report as a safety related component. It appears, however, that the component was not identified in the LRA requiring an AMR. Please indicate whether the subject component is in scope of license renewal requiring an AMR or justify its exclusion from aging management.

RAI 2.3.2.1-1 Response BSEP does not have a LPCI coupling as defined by BWRVIP-06.

As stated on page B-77 of the BSEP LRA:

BWRVIP-42, "LPCI Coupling Inspection and Flaw Evaluation Guidelines," is not applicable to BSEP. BSEP is a BWR-4 whose low pressure coolant injection function of the Residual Heat Removal System injects into the Reactor Coolant Recirculation system discharge lines rather than injecting directly into the reactor vessel.

NRC RAI 2.3.3.1-1 BSEP UFSAR Section 5.4.8.2 states that the RWCU System provides for continuous purification of the reactor water. Reactor coolant is removed from the Reactor Recirculation System, cooled in the regenerative and non regenerative heat exchangers, and processed through filter/

demineralizer units. The processed water is routed through the shell side of the regenerative heat exchanger and returned to the reactor vessel via the feedwater line. BSEP LRA Section 2.3.3.1, states that portions of the RWCU system support the integrity of the RCPB. LRA Table 2.3.3-1 identifies the license renewal intended function for the Regenerative Heat Exchanger (RHX) shell(s) and access cover(s) as only M4 "Provide structural support/seismic integrity" and does not identify M-1 "Provide pressure retaining boundary." This is in contrast to all other RWCU components listed in LRATable 2.3.3-1. Please provide additional information describing the basis for the RHX shell and access cover intended function in Table 2.3.3-1.

RAI 2.3.3.1-1 Response The Reactor Water Cleanup (RWCU) heat exchanger forms the termination point for the seismic evaluation of the safety related/non-safety related interface at the F042 valve. This boundary appears on drawing D-25027-LR, Sheet iB, Location E-6, for Unit No. 1, and D-02527-LR,

BSEP 05-0050 Page 15 of 87 Sheet 1B, Location E-6, for Unit No. 2. The RWCU heat exchangers are in a walled area in the Reactor Building that houses no safety related components and is sufficiently isolated/protected from other parts of the Reactor Building to preclude adverse spatial interactions (i.e., flooding, wetting, and spraying) with safety related components elsewhere in the building. Therefore, the RWCU heat exchangers intended function is solely related to structural support/seismic integrity.

The associated line connected to the heat exchanger (1/2-G31-50-4-907) is partially located outside this walled room and has been given the M-1, "Provide pressure retaining boundary,"

function due to spatial interaction considerations.

NRC RAI 2.3.3.1-2 BSEP UFSAR Section 5.4.8.2 states that the RWCU System provides for continuous purification of the reactor water. Reactor coolant is removed from the Reactor Recirculation System, cooled in the regenerative and non regenerative heat exchangers, and processed through filter/demineralizer units. The processed water is routed through the shell side of the regenerative heat exchanger and returned to the reactor vessel via the feed water line. BSEP LRA Section 2.3.3.1, states that portions of the RWCU system support the integrity of the RCPB.

License renewal boundary drawing D-25027-LR sheet IA at Quadrant E-4 and drawing D-25027-LR sheet lB at Quadrant D-3 show Unit 1 RHX shell "IC" and Unit 2 RHX shell "2C" as in scope for license renewal. However, the remaining Unit 1 and Unit 2 RHX shells "lA",

"1B", "2A", and "2B" and their associated piping are shown as not in scope for license renewal.

In addition, there are several piping sections between the RHX shells and a normally closed isolation valve that are also shown as not in scope. Please provide additional information to support your determination that these components and associated piping are not in scope for license renewal relative to the components intended function defined in LRA Section 2.3.3.1.

RAI 2.3.3.1-2 Response The components referenced in the RAI are non-safety related. As such, these components are not within the scope of License Renewal per 10 CFR 54.4(a)(1).

The non-safety related RWCU heat exchangers (i.e., "iC" and "2C"), discussed in the response to RAI 2.3.3.1-1, form the termination point for the seismic evaluation of the safety related/ non-safety related interface at the F042 valve. The "IA", "IB", "2A", and "2B" heat exchangers are not credited with seismic support of any safety related component. The RWCU heat exchangers are in a walled area in the Reactor Building that houses no safety related components and is sufficiently isolated/protected from other parts of the Reactor Building to preclude adverse spatial interactions (i.e., flooding, wetting, and spraying) with safety related components elsewhere in the building. Therefore, the "iC" and "2C" non-safety related RWCU heat exchangers are brought within the scope of License Renewal per 10 CFR 54.4(a)(2) but not the other non-safety related SSCs in the exclusion area.

The components not highlighted on the subject drawings are not required for a regulated event or equipment qualification per 10 CFR 54.4(a)(3).

BSEP 05-0050 Page 16 of 87 NRC RAI 2.3.3.1-3 BSEP UFSAR Section 6.2.3 states that safety objective of the secondary containment is to limit the release of radioactivity to the environs after a design basis accident (e.g., LOCA, refueling accident) so that the resulting exposures are kept to a practical minimum and are within 10 CFR 100 values. The in scope portion of lines 36-3-153 and 51-3-153 are shown on license renewal boundary drawing D-25027-LR, sheet 1A Quadrants B-8 and C-8 for Unit 1 and on license renewal boundary drawing D-25027-LR, sheet 1A Quadrants B-8 and C-8 for Unit 2.

Each line penetrates secondary containment (reactor building). It is not clear why portions of these lines between the inside of the reactor building and valves F035, F034 and F036 are not shown as in scope for license renewal. Please provide additional information justifying why these are not in scope for license renewal and why the scope does not include the remaining non isolable piping between the inside wall of the secondary containment and the adjacent piping to the valves F034, F035 and F036.

RAI 2.3.3.1-3 Response Please refer to the response to RAI 2.3.3.1-1 and RAI 2.3.3.1-2.

The portions of the RWCU System within the scope of License Renewal shown on License Renewal Boundary Drawing D-25027-LR, Sheet 1A, Locations B-8 and C-8, for Unit No. 1 and on License Renewal Boundary Drawing D-02527-LR, Sheet 1A, Locations B-8 and C-8, for Unit No. 2 are related to spatial interaction considerations. The License Renewal boundary flags indicate the transition to the walled area containing the RWCU heat exchangers in the Reactor Building that houses no safety related components and is sufficiently isolated/protected from other parts of the Reactor Building to preclude adverse spatial interactions (i.e., flooding, wetting, and spraying) with safety related components elsewhere in the building.

UFSAR Section 6.2 (e) describes Secondary Containment as follows:

The Primary Containment System is contained within the reactor building. This building, in conjunction with the reactor building heating and ventilating system and the Standby Gas Treatment (SGT) System, constitutes the fifth barrier to the release of fission products.

Section 2.4.2.8 of the LRA states:

The secondary containment system includes the Secondary Containment (Reactor Building) structure and the safety related systems provided to control the ventilation and cleanup of potentially contaminated volumes, exclusive of the Primary Containment, following a design basis accident.

SSCs in the RWCU System are neither considered part of the Reactor Building nor are they part of the safety related systems provided to control the ventilation and cleanup of potentially contaminated volumes.

BSEP 05-0050 Page 17 of 87 NRC RAI 2.3.3.1-4 BSEP LRA Unit 1 license renewal boundary drawing D-25027-LR sheet lB at Quadrant D6 and Unit 2 license renewal boundary drawing D-02527-LR sheet lB at Quadrant D6 show that the in scope portion of line 49-6-907 terminate in the middle of line 65-6-907. Since the in scope portion of 49-6-907 also includes two 3/4 inch capped vent connections, it is not clear why the non isolable portions connecting piping would not also be in scope. Please clarify the reason for terminating the scope at line 65-6-907 and not including non isolable portions connecting piping.

RAI 2.3.3.1-4 Response Line 1/2-G31-49-6-907 is a non-safety related line that was brought within the scope of License Renewal because it is required to protect the safety related/non-safety related boundary at valve 1/2-G31-F004. The highlighted portions of the License Renewal drawings indicate the extent of the piping included in the seismic evaluation. The License Renewal flag on Line 1/2-G31-49-6-907 indicates the terminus of the seismic evaluation.

NRC RAI 2.3.3.3-1 The BSEP USFAR, section 9.3.2.1.3, states that the Operational Sampling System including the Reactor Building Sampling (RXS) system is not required either for safe shutdown or following an accident and is therefore not classed as an essential system. However, it does interface with safety systems, and thus, the sample lines from nuclear safety systems or from engineered safeguard systems are provided with solenoid operated isolation valves operated remotely from local instruments or from the control room panel. The BSEP LRA Section 2.3.3.3 states the RXS system monitors the plant and equipment performance to determine routine chemical properties and radiation levels necessary to provide information for equipment operation, corrosion control, and radiation activity. The system also provides information for making operational decisions with regard to effectiveness, safety, and proper performance. Portions of the RXS system provide a pressure retaining boundary intended function for license renewal purposes.

• The pressure relief valves PRV-207, PRV-208, PRV-209 and PRV-210 and their associated piping on Unit 1 drawing D-70070-LR sheet 1 at Locations D-7, D-5, D-2 and D-1 are not shown as being included in scope for license renewal. However, the same pressure relief valves and associated piping shown on the Unit 2 drawing D-07070-LR sheet 1 at the same locations are shown as included in scope for license renewal.

• The piping and isolation valves V132, V133, V134, V135, V136, and V137 on Unit 1 drawing D-70070-LR sheet 1 at Locations D-4 through D-6 are not shown as being included in scope for license renewal. However, the same piping and isolation valves on the Unit 2 drawing D-07070-LR sheet 1 at the same locations are shown as included in scope for license renewal.

• The piping for pressure indicators PI-5220 (for both Unit 1 and 2), PI-5221, PI-5222 and PI-RO07A shown on Unit 1 drawing D-70070-LR sheet 1 at Locations D-5 through D-7

BSEP 05-0050 Page 18 of 87 are not shown as being included in scope for license renewal. However, the same piping for similar pressure indicators on the Unit 2 drawing D-07070-LR sheet 1 at the same locations are shown as included in scope for license renewal.

Failure of the above listed valves and associated piping that are not shown as being in scope for license renewal could prevent the RXS system from performing its intended function. Provide additional clarification and justification as to whether the above listed valves and associated piping should be or should not be included in scope for license renewal.

RAI 2.3.3.3-1 Response The subject components are within the RXS System License Renewal scoping boundary and subject to an aging management review.

NRC RAI 2.3.3.4-1 BSEP UFSAR Section 9.3.2.2 states that the purpose of the Post Accident Sampling System is to provide the capability of obtaining liquid and gas samples from the primary coolant system, primary containment, and the suppression chamber following an accident. LRA Section 2.3.3.4 states that the portions of PASS within the scope of License Renewal consist of components that are safety related and are relied upon to remain functional during and following design basis events, components which are non safety related whose failure could prevent satisfactory accomplishment of the safety related functions, and components that are part of the Environmental Qualification Program. LRATable 3.3.2 4 identifies the aging management intended function PASS in scope piping and fittings component type is M 1 "Provide pressure retaining boundary" and/or M 4 "Provide structural support/seismic integrity." The in scope license renewal boundaries identified at quadrant E-5 and E-6 on sheet 1 license renewal boundary drawings D-73027-LR and D-07327-LR terminate in the middle of a pipe run. Please provide additional information and discuss the basis for terminating the in scope portion of this piping downstream of solenoid valves SV-4180, SV-4181, SV-4184, and SV-4185 in the middle of the piping runs.

RAI 2.3.3.4-1 Response Lines 1/2-RXS-2 and 1/2-RXS-20 are non-safety related lines that were brought within the scope of License Renewal because they are required to protect the safety related/non-safety related boundary at valves 1/2-RXS-SV-4180/4181 and 1/2-RXS-SV-4184/4185 respectively. The highlighted portions of the License Renewal drawings indicate the extent of the piping included in the seismic evaluation. The License Renewal flags on Lines 1/2-RXS-2 and 1-RXS-20 indicate the terminus of the seismic evaluation.

BSEP 05-0050 Page 19 of 87 NRC RAI 2.3.3.6-1 In LRA Section 2.3.3.6, Screen Wash Water (SCW) System, it states that the SCW system consists of twelve traveling screens. The four traveling screens associated with the service water system were determined in scope, but the screens are active components, not subject to an AMR.

The application has not address the other eight traveling screens.

a.

The systems/components having intended functions as identified in 10 CFR 54.4(a) are within the scope of license renewal. Are the other eight traveling screens in scope or not?

If not, please identify where these eight traveling screens are located and explain the intended functions of the system.

b.

Based on the NRC review guidance in SRP-LR Table 2.1-5 and industry guidance, Appendix B to NEI 95-10, Rev. 3, for passive/active determination, the screen is not included as an active component in general. Justify the screen being an active component for Brunswick, or add screens to LRA Table 2.3.3-5 as a component requiring an AMR.

c.

Identify all the systems that have screens and were excluded from an AMR based on screens being active.

RAI 2.3.3.6-1 Response The SCW System traveling screens are provided for trash, fish, and larvae removal to minimize the fouling and clogging of water box tube sheets and piping and to protect fish and larvae. The traveling screens consist of a series of screen panels connected in a continuous loop across rotating drive sprockets. As water flows through the screen panels, debris, fish, and larvae are collected and held against the screens by the force of flowing water. As debris collects, the pressure differential between the inlet and outlet sides of the screens increases. During normal operations, when the pressure differential reaches the predetermined setpoint the Service Water (SW) screen rotates and the screen wash pumps wash the debris free. The Circulating Water (CW) screens operate continuously when the corresponding circulating water pump is operating and the screen wash pumps wash debris, fish, and larvae free.

Two traveling screens per unit (i.e., four total) act as filters for SW. These are in-scope for License Renewal because the SW System performs a safety related function. Four traveling screens per unit (i.e., eight total) act as filters for the CW System which provides condenser cooling. These eight traveling screens do not perform a License Renewal intended function.

Condenser cooling is not an intended function for the BSEP CW System. Refer to LRA section 2.3.3.5.

The screen panels are subcomponents of large, active assemblies which are monitored under the Maintenance Rule. The traveling screens can move at between 2.5 and 20 feet per minute and are considered active components. The screens are subject to periodic maintenance and replacement and are continuously monitored through control room annunciation. For BSEP License Renewal, the four in-scope traveling screens were determined to be active mechanical

BSEP 05-0050 Page 20 of 87 components. No other type of screen was excluded from the requirement of an aging management review on the basis of being classified as "Active."

NRC RAI 2.3.3.7-1 The BSEP UFSAR states that the Service Water system is designed to meet the service water flow requirements for normal operation (including normal operation, outage/shutdown operation, hurricane operation, and flood operation) and for operation during and subsequent to postulated design basis accident conditions. Drawing D-02041-LR, Sheet 1, Location F-2, has strainer 20-SW-ST-3 within the scope of license renewal; however, strainer 2-SW-ST-2 is not within the scope of license renewal. The BSEP LRA Table 2.3.3.6 states that basket strainers and CW strainers are in scope. Failure of this strainer could have an effect on the Intended Function to provide a pressure retaining boundary. Explain why strainer 2-SW-ST-2 is not within the scope of license renewal.

RAI 2.3.3.7-1 Response 2-SW-ST-2 was inadvertently omitted from highlighting. This component is in the scope of License Renewal and was subject to AMR.

NRC RAI 2.3.3.7-2a The BSEP UFSAR states that the Service Water system is designed to meet the service water flow requirements for normal operation (including normal operation, outage/shutdown operation, hurricane operation, and flood operation) and for operation during and subsequent to postulated design basis accident conditions. Drawing D-02041-LR, Sheet 1, Location F-1, has a LRA flag in the middle of a section of pipe which is continued on D-2041-3. The BSEP LRA Table 2.3.3.6 states that piping, fittings and valves are in scope. Failure of this section of pipe could have an effect on the Intended Function to provide a pressure retaining boundary. Explain why the LRA boundary occurs in the middle of this section of pipe.

RAI 2.3.3.7-2a Response The subject line supplies cooling water to the CW Pumps. It is non-safety related, but the portion of the line inside the SW Intake Structure is in License Renewal scope for potential spatial interaction. The boundary flag represents the location where the line exits the SW Intake Structure.

NRC RAI 2.3.3.7-2b The BSEP UFSAR states that the Service Water system is designed to meet the service water flow requirements for normal operation (including normal operation, outage/shutdown operation, hurricane operation, and flood operation) and for operation during and subsequent to postulated

BSEP 05-0050 Page 21 of 87 design basis accident conditions. The BSEP LRA Table 2.3.3.6 states that piping, fittings and valves are in scope. Drawing D-20041-LR, Sheet 1, Location F-8 has an LRA flag in the middle of a section of pipe which is continued on D-20041, sheet 3. The BSEP LRA Table 2.3.3.6 states that piping, fittings and valves are in scope. Failure of this section of pipe could have an effect on the Intended Function to provide a pressure retaining boundary. Explain why the LRA boundary occurs in the middle of this section of pipe.

RAI 2.3.3.7-2b Response The subject line supplies cooling water to the CW Pumps. It is non-safety related, but the portion of the line inside the SW Intake Structure is in License Renewal scope for potential spatial interaction. The boundary flag represents the location where the line exits the SW Intake Structure.

NRC RAI 2.3.3.7-3a The BSEP UFSAR states that the Service Water system is designed to meet the service water flow requirements for normal operation (including normal operation, outage/shutdown operation, hurricane operation, and flood operation) and for operation during and subsequent to postulated design basis accident conditions. Drawing D-02041-LR, Sheet 1, Locations A-8, A-6 and A-3, depict three lines each from the conventional header service water pumps with continuations on drawing F-4024. Drawing F-4024 was not provided with the LRA. The BSEP LRA Table 2.3.3.6 states that piping, fittings and valves are in scope. Failure of this section of pipe could have an effect on the Intended Function to provide a pressure retaining boundary. Provide additional information on where the LRA boundary is located for these sections of pipe.

RAI 2.3.3.7-3a Response The subject lines are the seal leakoff and lube oil cooler discharge lines on the Conventional SW Pumps. They are in scope to provide a discharge flow path in support of the operation of the pumps. All three lines discharge into an open hub drain, which drains directly down into the pump intake bay. Failure of the hub drain itself and the short run of pipe back to the pump bay could not obstruct the flow path of these lines, nor otherwise present a liability to the pump or nearby safety related equipment. As such, the hub drain and piping depicted on F-4024 perform no intended function and are not in the scope of License Renewal.

NRC RAI 2.3.3.7-3b The BSEP UFSAR states that the Service Water system is designed to meet the service water flow requirements for normal operation (including normal operation, outage/shutdown operation, hurricane operation, and flood operation) and for operation during and subsequent to postulated design basis accident conditions. Drawing D-20041-LR, Sheet 1, Locations B-i, B-6 and B-3, depict three lines each from the conventional header service water pumps with continuations on drawing F-04024. Drawing F-04024 was not provided with the LRA. The BSEP LRA

BSEP 05-0050 Page 22 of 87 Table 2.3.3.6 states that piping, fittings and valves are in scope. Failure of this section of pipe could have an effect on the Intended Function to provide a pressure retaining boundary. Provide additional information on where the LRA boundary is located for these sections of pipe.

RAI 2.3.3.7-3b Response The subject lines are the seal leakoff and lube oil cooler discharge lines on the Conventional SW Pumps. They are in scope to provide a discharge flow path in support of the operation of the pumps. All three lines discharge into an open hub drain, which drains directly down into the pump intake bay. Failure of the hub drain itself and the short run of pipe back to the pump bay could not obstruct the flow path of these lines, nor otherwise present a liability to the pump or nearby safety related equipment. As such, the hub drain and piping depicted on F-4024 perform no intended function and are not in the scope of License Renewal.

NRC RAI 2.3.3.7-4a The BSEP UFSAR states that the Service Water system is designed to meet the service water flow requirements for normal operation (including normal operation, outage/shutdown operation, hurricane operation, and flood operation) and for operation during and subsequent to postulated design basis accident conditions. Drawing D-02034-LR, Sheet 1, Locations F-2, and E-2, depict five (5) drains which include valves 2-SW-V444, V95, 2-SW-663, 2-SW-669 and 2-SW-664 that are not within the scope of license renewal. The BSEP LRA Table 2.3.3.6 states that piping, fittings and valves are in scope. Failure of these sections of pipe and valves could have an effect on the Intended Function to provide a pressure retaining boundary. Explain why these sections of pipe and valves are not within the scope of license renewal.

RAI 2.3.3.7-4a Response The subject piping/components are attached to the 36-inch SW discharge line. The non-safety related SW discharge line is in scope of License Renewal for providing a discharge flow path from safety related components in the Reactor Building to the CW System discharge tunnel/canal. The area it travels through under the Turbine Building houses no safety related components, so a pressure boundary failure of the piping does not represent a spatial interaction concern. As such, only the SW discharge flow path itself is in scope. Peripheral piping and components such as those identified above serve no intended function and are not within the scope of License Renewal.

NRC RAI 2.3.3.7-4b The BSEP UFSAR states that the Service Water system is designed to meet the service water flow requirements for normal operation (including normal operation, outage/shutdown operation, hurricane operation, and flood operation) and for operation during and subsequent to postulated design basis accident conditions. Drawing D-20034-LR, Sheet 2, Locations F-7, and D-8, depict five (5) drains which include valves 1-SW-V444, V95, 2-SW-663, 2-SW-669 and 2-SW-664 that

BSEP 05-0050 Page 23 of 87 are not within the scope of license renewal. The BSEP LRA Table 2.3.3.6 states that piping, fittings and valves are in scope. Failure of these sections of pipe and valves could have an effect on the Intended Function to provide a pressure retaining boundary. Explain why these sections of pipe and valves are not within the scope of license renewal.

RATI 2.3.3.7-4b Response The subject piping/components are attached to the 36-inch SW discharge line. The non-safety related SW discharge line is in scope of License Renewal for providing a discharge flow path from safety related components in the Reactor Building to the CW System discharge tunnel/canal. The area it travels through under the Turbine Building houses no safety related components, so a pressure boundary failure of the piping does not represent a spatial interaction concern. As such, only the SW discharge flow path itself is in scope. Peripheral piping and components such as those identified above serve no intended function and are not within the scope of License Renewal.

NRC RAI 2.3.3.7-5a The BSEP UFSAR states that the Service Water system is designed to meet the service water flow requirements for normal operation (including normal operation, outage/shutdown operation, hurricane operation, and flood operation) and for operation during and subsequent to postulated design basis accident conditions. Drawing D-02034-LR, Sheet 1, Locations E-2, and E-1, depict two (2) manholes that are not within the scope of license renewal. The BSEP LRA Table 2.3.3.6 states that piping, fittings and valves are in scope. Failure of these manholes could have an effect on the service water Intended Functions. Explain why these manholes are not within the scope of license renewal.

RATI 2.3.3.7-5a Response The subject piping/components are attached to the 36-inch SW discharge line. The non-safety related SW discharge line is in scope of License Renewal for providing a discharge flow path from safety related components in the Reactor Building to the CW System discharge tunnel/canal. The area it travels through under the Turbine Building houses no safety related components, so a pressure boundary failure of the piping does not represent a spatial interaction concern. As such, only the SW discharge flow path itself is in scope. Peripheral piping and components such as those identified above serve no intended function and are not within the scope of License Renewal.

NRC RAIT 2.3.3.7-5b The BSEP UFSAR states that the Service Water system is designed to meet the service water flow requirements for normal operation (including normal operation, outage/shutdown operation, hurricane operation, and flood operation) and for operation during and subsequent to postulated design basis accident conditions. Drawing D-20034-LR, Sheet 2, Locations D-8, and E-7, depict

BSEP 05-0050 Page 24 of 87 two (2) manholes that appear to be within the scope of license renewal. Please clarify if these manholes are within the scope of license renewal and if not, explain why these manholes are not within the scope of license renewal. Similar manholes for Unit 2 (shown on D-02034-LR, Sheet 1, Locations E-2, and E-1) are not within the scope of license renewal.

RAI 2.3.3.7-5b Response The subject piping/components are attached to the 36-inch SW discharge line. The non-safety related SW discharge line is in scope of License Renewal for providing a discharge flow path from safety related components in the Reactor Building to the CW System discharge tunnel/canal. The area it travels through under the Turbine Building houses no safety related components, so a pressure boundary failure of the piping does not represent a spatial interaction concern. As such, only the SW discharge flow path itself is in scope. Peripheral piping and components such as those identified above serve no intended function and are not within the scope of License Renewal.

NRC RAI 2.3.3.7-6a The BSEP UFSAR states that the Service Water system is designed to meet the service water flow requirements for normal operation (including normal operation, outage/shutdown operation, hurricane operation, and flood operation) and for operation during and subsequent to postulated design basis accident conditions. Drawing D-02034-LR, Sheet 1, Location E-2, depict three (3) sections of pipe which include valves 2-SW-V443 (2-SW-296-30-R-1) and 2-SW-299 (2-SW-266-1-R-2) and pipe line number (2-SW-22-30-R-1) that are not within the scope of license renewal. The BSEP LRA Table 2.3.3.6 states that piping, fittings and valves are in scope.

Failure of these sections of pipe and valves could have an effect on the Intended Function to provide a pressure retaining boundary. Explain why these sections of pipe and valves are not within the scope of license renewal.

RAI 2.3.3.7-6a Response The subject piping/components are attached to the 36-inch SW discharge line. The non-safety related SW discharge line is in scope of License Renewal for providing a discharge flow path from safety related components in the Reactor Building to the CW System discharge tunnel/canal. The area it travels through under the Turbine Building houses no safety related components, so a pressure boundary failure of the piping does not represent a spatial interaction concern. As such, only the SW discharge flow path itself is in scope. Peripheral piping and components such as those identified above serve no intended function and are not within the scope of License Renewal.

NRC RAI 2.3.3.7-6b The BSEP UFSAR states that the Service Water system is designed to meet the service water flow requirements for normal operation (including normal operation, outage/shutdown operation,

BSEP 05-0050 Page 25 of 87 hurricane operation, and flood operation) and for operation during and subsequent to postulated design basis accident conditions. Drawing D-20034-LR, Sheet 2, Location E-7, depict three (3) sections of pipe which include valves 2-SW-V443 (1-SW-296-30-R-1) and 1-SW-299 (1-SW-228-1-R-2) and pipe line number (1-SW-22-30-R-1) that are not within the scope of license renewal. The BSEP LRA Table 2.3.3.6 states that piping, fittings and valves are in scope.

Failure of these sections of pipe and valves could have an effect on the Intended Function to provide a pressure retaining boundary. Explain why these sections of pipe and valves are not within the scope of license renewal.

RAI 2.3.3.7-6b Response The subject piping/components are attached to the 36-inch SW discharge line. The non-safety related SW discharge line is in scope of License Renewal for providing a discharge flow path from safety related components in the Reactor Building to the CW System discharge tunnel/canal. The area it travels through under the Turbine Building houses no safety related components, so a pressure boundary failure of the piping does not represent a spatial interaction concern. As such, only the SW discharge flow path itself is in scope. Peripheral piping and components such as those identified above serve no intended function and are not within the scope of License Renewal.

NRC RAI 2.3.3.7-7a The BSEP UFSAR states that the Service Water system is designed to meet the service water flow requirements for normal operation (including normal operation, outage/shutdown operation, hurricane operation, and flood operation) and for operation during and subsequent to postulated design basis accident conditions. Drawing D-02041-LR, Sheet 2, Locations B-3 and B-6 depict three lines each from the nuclear header service water pumps. The BSEP LRA Table 2.3.3.6 states that piping, fittings and valves are in scope. Failure of this section of pipe could have an effect on the Intended Function to provide a pressure retaining boundary. Provide additional information as to where the LRA boundary is located for these sections of pipe.

RAI 2.3.3.7-7a Response The subject lines are the seal leakoff and lube oil cooler discharge lines on the Nuclear SW Pumps. They are in scope to provide a discharge flow path in support of the operation of the pumps. All three lines discharge into an open hub drain, which drains directly down into the pump intake bay. Failure of the hub drain itself and the short run of pipe back to the pump bay could not obstruct the flow path of these lines, nor otherwise present a liability to the pump or nearby safety related equipment. As such, the hub drain and piping depicted on F-4024 perform no intended function and are not in the scope of License Renewal.

BSEP 05-0050 Page 26 of 87 NRC RAI 2.3.3.7-7b The BSEP UFSAR states that the Service Water system is designed to meet the service water flow requirements for normal operation (including normal operation, outage/shutdown operation, hurricane operation, and flood operation) and for operation during and subsequent to postulated design basis accident conditions. Drawing D-20041-LR, Sheet 2, Locations B-3 and B-6 depict three lines each from the nuclear header service water pumps with continuations on drawing F40024. Drawing F-40024 was not provided with the LRA. The BSEP LRA Table 2.3.3.6 states that piping, fittings and valves are in scope. Failure of this section of pipe could have an effect on the Intended Function to provide a pressure retaining boundary. Provide additional information as to where the LRA boundary is located for these sections of pipe.

RAI 2.3.3.7-7b Response The subject lines are the seal leakoff and lube oil cooler discharge lines on the Nuclear SW Pumps. They are in scope to provide a discharge flow path in support of the operation of the pumps. All three lines discharge into an open hub drain, which drains directly down into the pump intake bay. Failure of the hub drain itself and the short run of pipe back to the pump bay could not obstruct the flow path of these lines, nor otherwise present a liability to the pump or nearby safety related equipment. As such, the hub drain and piping depicted on F40024 perform no intended function and are not in the scope of License Renewal.

NRC RAI 2.3.3.7-8a The BSEP UFSAR states that the Service Water system is designed to meet the service water flow requirements for normal operation (including normal operation, outage/shutdown operation, hurricane operation, and flood operation) and for operation during and subsequent to postulated design basis accident conditions. Drawing D-02041-LR, Sheet 2, Location F-7 has a LRA flag in the middle of a section of pipe which is continued on D-2041-3 and D-2034. The BSEP LRA Table 2.3.3.6 states that piping, fittings and valves are in scope. Failure of this section of pipe could have an effect on the Intended Function to provide a pressure retaining boundary. Explain why the LRA boundary occurs in the middle of this section of pipe.

RAI 2.3.3.7-8a Response The subject line is the SW Supply to non-safety related cooling loads in the Turbine Building, as well as the fill line to the CW System. Line 2-SW-100-30-R-1 is a non-safety related line that was brought within the scope of License Renewal because it is required to protect the safety related/non-safety related boundary at valve 2-SW-V3. The highlighted portions of the License Renewal drawings indicate the extent of the piping included in the seismic evaluation. The License Renewal flag on Line 2-SW-100-30-R-1 indicates the terminus of the seismic evaluation.

BSEP 05-0050 Page 27 of 87 NRC RAI 2.3.3.7-8b The BSEP UFSAR states that the Service Water system is designed to meet the service water flow requirements for normal operation (including normal operation, outage/shutdown operation, hurricane operation, and flood operation) and for operation during and subsequent to postulated design basis accident conditions. Drawing D-20041-LR, Sheet 2, Location F-2 has a LRA flag in the middle of a section of pipe which is continued on D-20034 and D-20041-3. The BSEP LRA Table 2.3.3.6 states that piping, fittings and valves are in scope. Failure of this section of pipe could have an effect on the Intended Function to provide a pressure retaining boundary. Explain why the LRA boundary occurs in the middle of this section of pipe.

RAI 2.3.3.7-8b Response The subject line is the SW Supply to non-safety related cooling loads in the Turbine Building, as well as the fill line to the CW System. Line 1-SW-16-30-R-1 is a non-safety related line that was brought within the scope of License Renewal because it is required to protect the safety related/non-safety related boundary at valve 1-SW-V3. The highlighted portions of the License Renewal drawings indicate the extent of the piping included in the seismic evaluation. The License Renewal flag on Line 1-SW-16-30-R-1 indicates the terminus of the seismic evaluation.

NRC RAI 2.3.3.7-9a The BSEP UFSAR states that the Service Water system is designed to meet the service water flow requirements for normal operation (including normal operation, outage/shutdown operation, hurricane operation, and flood operation) and for operation during and subsequent to postulated design basis accident conditions. Drawing D-02537-LR, Sheet 2, Location B-2 has a LRA flag in the middle of a section of pipe which is continued on D-2544. The BSEP LRA Table 2.3.3.6 states that piping, fittings and valves are in scope. Failure of this section of pipe could have an effect on the Intended Function to provide a pressure retaining boundary. Explain why the LRA boundary occurs in the middle of this section of pipe.

RAI 2.3.3.7-9a Response Line 2-G16-1178-1-160 is a non-safety related line that was brought within the scope of License Renewal because it is required to protect the safety related/non-safety related boundary at valve 2-E11-F073. The highlighted portions of the License Renewal drawings indicate the extent of the piping included in the seismic evaluation. The License Renewal flag on Line 2-G16-1178-1-160 indicates the terminus of the seismic evaluation.

NRC RAI 2.3.3.7-9b The BSEP UFSAR states that the Service Water (SW) System is designed to meet the service water flow requirements for normal operation (including normal operation, outage/shutdown operation, hurricane operation, and flood operation) and for operation during and subsequent to

BSEP 05-0050 Page 28 of 87 postulated design basis accident conditions. Drawing D-25037-LR, Sheet 2, Location B-2 has a LRA flag in the middle of a section of pipe which is continued on D-25043 Sheet 1B. The BSEP LRA Table 2.3.3.6 states that piping, fittings and valves are in scope. Failure of this section of pipe could have an effect on the Intended Function to provide a pressure retaining boundary.

Explain why the LRA boundary occurs in the middle of this section of pipe.

RAI 2.3.3.7-9b Response Line 1-G16-1177-1-160 is a non-safety related line that was brought within the scope of License Renewal because it is required to protect the safety related/non-safety related boundary at valve 1-E11-F073. The highlighted portions of the License Renewal drawings indicate the extent of the piping included in the seismic evaluation. The License Renewal flag on Line 1-G16-1177-1-160 indicates the terminus of the seismic evaluation.

NRC RAI 2.3.3.8-1 BSEP UFSAR Section 9.2.2.2 states that the RBCCW system pumps, heat exchangers, and equipment required for normal system heat removal are designed to Class II requirements.

Portions of the system, which penetrate primary containment, including the isolation valves, were designed to Class I requirements to meet containment integrity. BSEP LRA section 2.3.3.8 states that the RBCCW system removes heat from the reactor auxiliary systems and their related accessories during normal operation. LRA section 2.3.3.8 also states that the system also provides an additional barrier between contaminated systems and the service water discharged to the environment. BSEP LRA Table 3.3.2 7 identifies the Piping (Pipe, Fittings, and Flanges) as being in scope for license renewal to provide a pressure retaining boundary (MI) function.

License Renewal boundary drawing D 25038 LR, Sheet 2 at quadrants C4 and D4 shows the LR boundary terminating in the middle of non isolable portions of lines 1-RCC-6-6-154 and 1-RCC-54-2-154. License Renewal boundary drawing D-02538-LR, Sheet 2 at quadrants C4 and D4 also indicates that the LR boundary terminates in the middle of non isolable portions of lines 2-RCC-6-6-154 and 2-RCC-54-2-154. Please discuss the basis for terminating the in scope portion of the piping at these locations and provide additional information describing the as built plant locations that these scope boundaries represent.

RAI 2.3.3.8-1 Response The subject Reactor Building Closed Cooling Water (RBCCW) piping provides cooling water to heat loads in the RWCU System. This piping performs no safety related function. In general, portions of the RBCCW System that are highlighted are in License Renewal scope for potential spatial interaction. The scoping boundary described above represents the point at which RBCCW enters a walled area in the Reactor Building that houses no safety related components and is sufficiently isolated/protected from other parts of the Reactor Building to preclude adverse spatial interactions with safety related components elsewhere in the building.

BSEP 05-0050 Page 29 of 87 NRC RAI 2.3.3.8-2 BSEP LRA Section 2.3.8 states that the RBCCW System provides cooling for Cleanup Recirculation Pump Coolers. BSEP Unit 1 license renewal boundary drawing D-25038-LR, Sheet 2 at Quadrant El and E2 identifies a portion of the RBCCW supply piping to cleanup recirculation pump cooler lB (1-RCC-57-1 1/2-154) and adjacent valve V304 as in scope for license renewal. This is inconsistent with the RBCCW piping and valve combination for the remaining Unit 1 cleanup recirculation pump cooler IA (1-RCC-56-1 1/2-154 and V307) is shown as not in scope for license renewal. Also, the equivalent RBCCW supply piping and valve combinations to the Unit 2 cleanup recirculation pump coolers 1A and lB are shown as not in scope for license renewal on BSEP boundary drawing D-02538-LR, Sheet 2 at Quadrants El and E2 and at Quadrants DI and D2. Please discuss the basis for terminating the in scope portion of the piping at these locations and provide additional information describing the as built plant locations that the in scope boundaries represent.

RAI 2.3.3.8-2 Response The subject line does not perform a safety related function and is located in an area that is sufficiently isolated/protected from other parts of the Reactor Building to preclude adverse spatial interactions with safety related components. See the response to RAI 2.3.3.8-1, for additional information. License Renewal boundary drawing D-25038-LR, Sheet 2, will be revised to remove highlighting from these components.

NRC RAI 2.3.3.10-1 Brunswick UFSAR Section 8.3.1.1.6 states that the Diesel Generator (DG) system has several auxiliary support systems that must function in order to perform its safety related functions including the diesel fuel oil system. There are two sections of piping associated with fuel oil transfer pump 2A shown on drawing D-02268-LR sheet 1B at Locations B-3 and B-4 that are shown as being out of scope for license renewal. This is not consistent with the fuel transfer pump IA shown on drawing D-02268-LR sheet 1A at Locations B-3 and B4 which shows the same piping sections as being in scope. Failure of the out of scope piping may affect the pressure boundary integrity of the fuel oil transfer system adversely impacting the system. A degraded fuel oil system could adversely impact the ability of the Diesel Engine No. 2 to perform its safety related function. Provide additional clarification or justification to support the determination that it is acceptable to not include these sections of piping as in scope for license renewal.

RAI 2.3.3.10-1 Response The subject piping is within the Diesel Fuel Oil System License Renewal scoping boundary and subject to an aging management review.

BSEP 05-0050 Page 30 of 87 NRC RAI 2.3.3.10-2 Brunswick UFSAR Section 8.3.1.1.6 states that the DG system has several auxiliary support systems that must function in order to perform its safety related functions including the diesel fuel oil system. There are several blind flanges and fittings for the diesel generator fuel oil storage tanks listed below that are not consistently treated as being either in scope or out of scope for license renewal.

DG No. 1 fuel oil day tank the 2" blind flange on drawing D-02268-LR sheet 1A at Location F-6 is shown as being out of scope.

DG No. 1 four day storage tank the 6" blind flange, 24" Man Hole, and 2" blind flange on drawing D-02268-LR sheet 1A at Locations C-4, and B-5 are shown as in scope.

DG No. 1 fuel oil transfer pump 1B on drawing D-02268-LR sheet IA at Location C-2 has a discharge pressure tap pipe plug down stream of PI-1242-6 that is shown as being out of scope. This is inconsistent with fuel oil transfer pump LA that has a similar pipe plug downstream of PI-1241-6 that is shown as in scope.

DG No. 2 fuel oil day tank the 2" blind flange on drawing D-02268-LR sheet lB at Location F-6 is shown as being out of scope.

DG No. 2 four day storage tank the 6" blind flange on drawing D-02268-LR sheet 1B at Location C4 is shown as out of scope.

DG No. 3 fuel oil day tank the 2" blind flange on drawing D-02269-LR sheet 2A at Location F-6 is shown as being out of scope.

DG No. 3 four day storage tank the 6" blind flange, 24" Man Hole, and 2" blind flange on drawing D-02269-LR sheet 2A at Locations C-4, and B-5 are shown as in scope.

The diesel seven day storage tank shown on drawing D-02269-LR sheet 2A at Location B-7 shows a man way, an instrument line flanged access, and a tank fill line that are shown as being out of scope.

DG No. 4 fuel oil day tank the 2" blind flange, 2" blind flange and 6" blind flange on drawing D-02269-LR sheet 2B at Location F-6, B-5 and C4 are shown as being out of scope.

Failure of the blind flanges and fittings listed above that are shown as out of scope may affect the pressure boundary integrity of the fuel oil transfer system adversely impacting the system. A degraded fuel oil system could adversely impact the ability of the Diesel Engines to perform their safety related functions. Provide additional clarification or justification to support the determination that it is acceptable to not include the blind flanges and fittings listed above as in scope for license renewal.

RAI 2.3.3.10-2 Response The subject components are either piece-parts or miscellaneous appendages of in-scope components. The listed flanges and fittings are conservatively assumed to be within the Diesel Fuel Oil System License Renewal scoping boundary and subject to an aging management review.

BSEP 05-0050 Page 31 of 87 NRC RAI 2.3.3.10-3 Brunswick UFSAR Section 8.3.1.1.6 states that the DG system has several auxiliary support systems that must function in order to perform its safety related functions including the diesel lube oil system. There are several instrument lines, fittings and piping segments for the diesel generator lube oil systems listed below that are not consistently treated as being either in scope or out of scope for license renewal.

DG No. 1 engine control panel pressure gage PI-6520 piping on drawing D-02270-LR sheet 1A at Location F-7 is shown as out of scope. This is inconsistent with similar pressure gage piping for DG No. 2 on drawing D-02270-LR sheet lB at the same Location that is shown as in scope.

DG No. 2 sensing line for TI-6542-2 on drawing D-02270-LR sheet lB at Location C-6 is shown as in scope. This is inconsistent with similar sensing lines for DG No. 1 on drawing D-02270-LR sheet IA at the same Location that is shown as out of scope. This same sensing line for DG No. 3, TI-6542-3, and DG No. 4, TI-6542-4, are also shown as out of scope.

DG No. 1 level switch LS-6562-1 piping on drawing D-02270-LR sheet 1A at Location E-6 is shown as out of scope. This is inconsistent with similar level switch piping for DG No. 2 on drawing D-02270-LR sheet lB at the same Location that is shown as in scope.

DG No. 2 pipe cap downstream of SS-6577-2-10 on drawing D-02270-LR sheet lB at Location E-5 is shown as out of scope. This is inconsistent with similar pipe caps for DG No. 1 on drawing D-02270-LR sheet 1A at the same Location that is shown as in scope.

This same pipe cap is also shown as in scope for DG No. 3 and DG No. 4.

For DG nos. 1, 3 and 4 there is a three inch diameter piping segment on drawings 0-02270-LR Sheet 1A at Location E-4, D-02271-LR sheet 2A at Location B4, and D-02271-LR sheet 2B at Location B-4 shown as out of scope. This is inconsistent with DG No. 2 that shows the same three inch diameter piping segment at the same Location as in scope.

Failure of the instrument lines, fittings and piping segments listed above that are shown as out of scope may affect the pressure boundary integrity of the diesel lube oil system adversely impacting the system. A degraded diesel lube oil system could adversely impact the ability of the Diesel Engines to perform their safety related functions. Provide additional clarification or justification to support the determination that it is acceptable to not include the instrument lines, fittings and piping segments listed above as in scope for license renewal.

RAI 2.3.3.10-3 Response The subject components are within the Diesel Lube Oil System License Renewal scoping boundary and subject to an aging management review.

BSEP 05-0050 Page 32 of 87 NRC RAI 2.3.3.10-4 Brunswick UFSAR Section 8.3.1.1.6 states that the DG system has several auxiliary support systems that must function in order to perform its safety related functions including the diesel service water system. The license renewal documentation shows inconsistencies in how the vent piping and pipe caps are shown for this system. For DG No. 1 there is a vent pipe and pipe caps on drawing D-02274-LR sheet 1 at Location E-3 that are shown as out of scope. There is also a pipe cap for DG No' 2 on drawing D-02274-LR sheet 1 at Location E-6 that is shown as out of scope. The same vent piping and pipe caps for DG No. 3 and DG No. 4 on drawing D-02274-LR sheet 2 at the same locations are shown in scope. The piping and pipe caps are downstream of isolation valves, but it is not clear if all of the isolation valves are normally closed. If these isolation valves are not normally closed, failure of the piping and pipe caps could have an adverse impact on the diesel service water system. A degraded service water system could adversely impact the ability of the Diesel Engines to perform their safety related function.

Provide additional clarification or justification for not including these sections of piping and pipe caps as in scope for license renewal.

RAI 2.3.3.10-4 Response The subject components are miscellaneous appendages of in-scope components. The listed vent and pipe caps are conservatively assumed to be within DG SW System License Renewal scoping boundary and subject to an aging management review.

NRC RAI 2.3.3.10-5 Brunswick UFSAR Section 8.3.1.1.6 states that the Diesel Generator (DG) system has several auxiliary support systems that must function in order to perform its safety related functions including the diesel exhaust and crankcase vacuum blower system. For all diesel generators the crankcase vacuum blower discharge lines shown on drawings D-02267-LR sheets 1 and 2 at Locations C-3 and C-6 are not shown as in scope. The crankcase vacuum blower system ensures potentially dangerous crankcase vapors are exhausted to the atmosphere. It is not clear that the crankcase vacuum blower system could perform its intended function if the discharge lines are damaged, pinched off, fail or are otherwise restricted. Failure of the crankcase vacuum blower discharge lines may affect the pressure boundary integrity of the diesel generator crankcase vacuum blower system. A degraded crankcase vacuum blower system could adversely impact the ability of the Diesel Engines to perform their safety related functions. Provide additional clarification or justification to support the determination that it is acceptable to not include the crankcase vacuum blower discharge lines as in scope for license renewal.

RAI 2.3.3.10-5 Response The piping down stream of the four diesel crank case vacuum blowers is classified in the plant design records as non-safety related and is not credited as being required for any of the 10 CFR 54.4(a)(3) events. The prospect of "pinching off" of these lines and thus restricting crank case ventilation is a hypothetical event outside of the CLB. Potential age-related

BSEP 05-0050 Page 33 of 87 degradation of the piping could allow the leakage of crank case fumes into the diesel building but would not impact the safety function of the diesel generators. While personnel safety is always an important consideration and subject to corrective action, it is not addressed as a scoping consideration under 10 CFR 54.4.

NRC RAI 2.3.3.12-1 The BSEP UFSAR states that the Non-Interruptible Instrument Air system is designed with the capability of supplying all instrument air requirements in the reactor building required for plant safety during normal operation. The Nitrogen Backup System provides an independent safety related pneumatic source to selected safety-related loads in the event of either a LOCA or loss of pneumatic supply. The BSEP LRA Section 2.3.3.12 states that components in the IA system automatically actuate and monitor nitrogen backup supplies when required. Components in the IA system provide the primary containment isolation function following design basis events.

The IA receivers IA, 1B, 2A, 2B are in scope and provide a pressure retaining boundary function, however, none of the air receiver discharge lines that allow the system to provide IA to components are identified as in scope on the following drawings:

D-70029-LR,Sheet 2B at Location E-7 (line 221-2-170)

D-72006-LR, Sheet 4 at Location B-1 (line 201-2-170, 206-2-170, 215-2-170, 220-2-170)

D-07029-LR Sheet 2A at Location F-1 (line 201-2-170, 251-2-170, 203-2-170)

D-07029-LR, Sheet 2B at Location E-7 (line 221-2-170)

Failure of the identified lines could prevent the IA system from performing its required safety functions. Provide additional information and justify your determination to exclude the identified lines from the scope of license renewal.

RAI 2.3.3.12-1 Response The referenced Instrument Air (IA) Receivers 1A, lB, 2A, 2B are located in the Unit 1 and Unit 2 Reactor Buildings and quality classified as non-safety related. These air receivers are discussed in UFSAR Section 3.5.1.1. The IA System safety evaluation is described in UFSAR Section 9.3.1.2.3. BNP-LR-007, "License Renewal Scoping Calculation For Criteria 10 CFR 54.4(a)(2) Nonsafety Affecting Safety-Related Equipment," Revision 2, page 20 states:

Missiles may be generated by failure of compressed air tanks located within buildings/structures. The Reactor Building air receivers are located in the vicinity of safety related equipment, hence these receivers are included in the scope of License Renewal.

Thus, the referenced IA Receivers IA, lB, 2A, and 2B are in the scope of License Renewal for a spatial interaction, not a functional relationship. The plant does not rely on the instrument air in these receivers to accomplish the function of a safety related or a regulated event component.

BSEP 05-0050 Page 34 of 87 Failure of the identified lines would not prevent the IA System from performing its required safety functions.

NRC RAI 2.3.3.12-2 The BSEP USFAR states that the Non-Interruptible Instrument Air system is designed with the capability of supplying all instrument air requirements in the reactor building required for plant safety during normal operation. The Nitrogen Backup System provides an independent safety-related pneumatic source to selected safety-related loads in the event of either a LOCA or loss of pneumatic supply. The BSEP LRA Section 2.3.3.12 states that components in the IA system automatically actuate and monitor nitrogen backup supplies when required. Components in the IA system provide the primary containment isolation function following design basis events.

Drawings D-70077-LR, Sheet 3A and D-07077-LR, Sheet 3A both identify the valve B32-F020 at Location B-1 as being in scope for license renewal. However, the lines connecting valve B32-F020 to the IA header are not shown as being within scope. Failure of the piping could cause loss of function of valve B32-F020. Provide additional information and justify your determination to exclude the piping that connects the IA header to valve B32-F020.

RAI 2.3.3.12-2 Response Valve B32-F020 is a Recirculation Sample Line Isolation Valve, which is a safety related valve in System 2020. Per Design Basis Document, DBD-002, "Reactor Coolant Recirculation System," Revision 9, Section 4.4.3, this valve is an air-operated globe valve, which receives automatic closure signals. This valve has alternating current solenoid pilots which de-energize to vent air from the diaphragm to allow valve closure by spring action using de-energize-to-close "fail-safe" logic.

The IA System is not required for valve B32-F020 to perform its safety related function. Failure of the instrument air piping would not cause loss of function of valve B32-F020. This valve fails to the safe position without IA supply. Non-safety related IA lines connecting valve B32-F020 to the IA header are correctly shown as not being within scope.

NRC RAI 2.3.3.14-1 The BSEP UFSAR states that the Pneumatic Nitrogen system is designed to supply drywell pneumatic requirements (including selected safety related loads) during normal plant operation.

The BSEP LRA Section 2.3.3.14 states that piping and valves are in scope. Drawing D-02494-LR, Sheet 1, Location F-2, has a section of piping with a continuation to D-07077-3A, Location F-6 that is not within the scope of license renewal. Note that the continuation could not be found on D-07077-3A, Location F-6. Failure of this section of piping could have an effect on the Intended Function to provide structural support and seismic integrity. Provide additional justification as to why this section of pipe is not within the scope of license renewal.

BSEP 05-0050 Page 35 of 87 RAI 2.3.3.14-1 Response Pneumatic Nitrogen System (PNS) Line 2-PNS-001-3/4-167 is a non-safety related line that was brought within the scope of License Renewal because it is required to protect the safety related/non-safety related boundary at valve 2-RNA-SV-5262.

The License Renewal boundary flag on Drawing D-02494-LR, Sheet 1, should have been placed upstream of the reducer (i.e., upstream of 2-RNA-V255) to match the boundary flag location on Drawing D-07077-LR, Sheet 3A.

Line 2-PNS-3-1/2-154 is a non-safety related line that is not within the scope of License Renewal because it is upstream of the corrected License Renewal boundary flag and its failure does not affect the seismic qualification of the safety related/non-safety related boundary at valve 2-RNA-SV-5262.

It should be noted that the components upstream of the correct boundary flag location were inadvertently included within the scope of License Renewal. These components are: 2-PNS-V6, 2-PNS-V8, 2-PNS-V17, 2-PNS-V5003, 2-PNS-V5004, 2-PNS-V5005, 2-PNS-V12, 2-PNS-RO-5829, and 2-PNS-FLT-100.

NRC RAI 2.3.3.14-2 The BSEP UFSAR states that the Pneumatic Nitrogen system is designed to supply drywell pneumatic requirements (including selected safety-related loads) during normal plant operation.

The BSEP LRA Section 2.3.3.14 states that piping and valves are in scope. Drawing D-02494-LR, Sheet 1, at Location F-3, depicts the piping, isolation and bypass valves to 2-PNS-FLT-100 to be within the scope of license renewal. A similar piping arrangement for 2-PNS-FLT-101 on drawing D-07077, sheet 3B, at Location C-3 is shown out of scope. Provide additional information and justification as to why this section of piping, valves and filter for FLT-101 is not within the scope of license renewal.

RAI 2.3.3.14-2 Response See the response to RAI 2.3.3.14-1 for additional information. Line 2-PNS-002-3/4-167 is a non-safety related line that was brought within the scope of License Renewal because it is required to protect the safety related/ non-safety related boundary at valve 2-RNA-SV-5261.

The License Renewal boundary flag on Drawing D-02494-LR, Sheet 1, should have been placed upstream of the reducer (i.e., upstream of 2-RNA-V256) to match the boundary flag location on Drawing D-07077-LR, Sheet 3B.

Filter 2-PNS-FLT-101 and the associated valves 2-PNS-V5006, 2-PNS-V5007, and 2-PNS-V5008 are beyond the correct License Renewal boundary flag and are consequently not required to be within the scope of License Renewal.

BSEP 05-0050 Page 36 of 87 It should be noted that the components upstream of the correct boundary flag location were inadvertently included within the scope of License Renewal. These components are: 2-PNS-V3, 2-PNS-V18, 2-PNS-V7, 2-PNS-V11, and 2-PNS-RO-5830.

NRC RAI 2.3.3.14-3 The BSEP UFSAR states that the Pneumatic Nitrogen system is designed to supply drywell pneumatic requirements (including selected safety-related loads) during normal plant operation.

The BSEP LRA Section 2.3.3.14 states that piping and valves are in scope. Drawing D-07077-LR, Sheet 3A, Location C-6, shows a license renewal boundary designator [LR]

between valves V255 and 2-PNS-V5004. Drawing D-02494-LR, Sheet 1, Location F-3, indicates the piping between V255 and V5004 as in-scope and piping and valves from PSL 5843A2, 2-PNS-V12, and 2-PNS-V8 to V255, including 2-PNS-V5004 are within the scope of license renewal. The piping between 2-PNS-V12, 2-PNS-V8, 2-PNS-V5004 is shown not shaded on D07077 Sheet 3A. A similar situation exists with drawing D-02494-LR, Sheet 1 and D-07077-LR, Sheet 3B from V256 through 2-PNS-V11 & 2-PNS-V7. Please explain these apparent license renewal boundary discrepancies between drawing D-02494-LR, Sheet 1 and drawing D-07077-LR, Sheet 3A&B and provide justification for why the piping between 2-PNS-V12, 2-PNS-V8, 2-PNS-V5004 is not shown as in scope on drawing D07077 sheet 3A.

RAI 2.3.3.14-3 Response Please refer to the responses to RAI 2.3.3.14-1 and RAI 2.3.3.14-2 for additional information.

The License Renewal boundary flags on Drawings D-07077, Sheet 3A and Sheet 3B, are associated with the piping upstream of the safety related/non-safety related boundaries for valves 2-RNA-SV-5262 and 2-RNA-SV-5261, respectively. As discussed in the responses to RAI 2.3.3.14-1 and RAI 2.3.3.14-2, the License Renewal boundary flags shown on drawing D-02494, Sheet 1 are incorrect. Placing the License Renewal boundary flags in the correct location will remove the discrepancies among the three referenced drawings: D-02494-LR, Sheet 1, D-07077-LR, Sheet 3A, and D-07077-LR, Sheet 3B.

NRC RAI 2.3.3.15-1 UFSAR Section 9.5.1.4.1.4 discusses the water fire protection system, including the fixed manual suppression system hose stations with hose racks and hose reels. LRA Section 2.3.3.15 references drawing F-02315-LR, sheet 1 for license renewal scoping boundaries for the Fire Protection system. Drawing F-02315-LR, sheetl shows hose station/hose racks AOG 59 and AOG-60, and hose station/hose reels AOG-57, AOG-58, and AOG 61 in scope. Hose station/hose reel AOG-62 is shown out of scope. Please justify hose station/hose reel AOG-62 as out of scope.

BSEP 05-0050 Page 37 of 87 RAI 2.3.3.15-1 Response AOG-62 was incorrectly classified in the EDB and, therefore, was not included in scope.

However, AOG-62 is in scope and should have been marked on drawing F-02315-LR as within the scoping boundary.

NRC RAI 2.3.3.15-2 UFSAR Section 9.5.1.4.1.4 discusses the water fire protection system, including the fixed manual suppression system hose stations with hose racks and hose reels. In UFSAR Section 9.5.1.5, the specific fire hazards analysis for fire area MWT-1 Makeup Water Treatment states: 'Manual fire fighting in the area should not be difficult. A hose line and portable fire extinguishers are available in the area to assist in manual fire fighting." LRA Section 2.3.3.15 references drawing D-02304-LR for license renewal scoping boundaries for the Fire Protection system. On Drawing D-02304-LR, Hose station/hose reel 2-WT-HR-#1 is shown out of scope.

Please justify this hose station/hose reel as out of scope.

RAI 2.3.3.15-2 Response The EDB quality classifications for credited fire protection components are B-31, B-32, B-33, B-34, B-35, and B-42. The hose reel, 2-FP-WT-HR-1, is classified as quality class D-99 (i.e.,

non-seismic/non-safety related). The BSEP fire protection commitment document does not identify a commitment for hose reels within the Water Treatment Building. As such, the subject hose reel does not support a License Renewal fire protection intended function, and is correctly identified as out of scope.

NRC RAI 2.3.3.15-3 UFSAR Section 9.5.1.4.1.4 discusses the water fire protection system, including the fixed automatic suppression system. In UFSAR Section 9.5.1.5, the specific fire hazards analysis for fire area MWT-1 Makeup Water Treatment states: "Fire protection includes an automatic sprinkler system with heads located at the ceiling level." LRA Section 2.3.3.15 references drawing D-02304-LR for license renewal scoping boundaries for the Fire Protection system. On Drawing D-02304-LR (B-8), Sprinkler nozzle 764-I-J-2 is shown out of scope. Please justify this sprinkler nozzle as out of scope.

RAI 2.3.3.15-3 Response Sprinkler pipe was inadvertently not highlighted on Drawing D-02304. The sprinkler piping is in scope for License Renewal.

BSEP 05-0050 Page 38 of 87 NRC RAI 2.3.3.15-4 UFSAR Section 9.5.1.4.1.4 discusses the water fire protection system, including the fixed manual suppression system foam-water hose stations located in the diesel generator building to provide backup suppression for the four-day tank rooms and the oil bath air filters. In UFSAR Section 9.5.1.5, the specific fire hazards analysis for fire areas DG-19 Fuel Oil Tank Cell 1, DG-20 Fuel Oil Tank Cell 2, DG-21 Fuel Oil Tank Cell 3, and DG-22 Fuel Oil Tank Cell 4 states: "Manual fire fighting could be difficult should a significant oil fire occur. Because the tanks are located below grade, access for fire fighting could be difficult. A foam standpipe is available from an adjacent area." LRA Section 2.3.3.15 references drawing D-02301-LR for license renewal scoping boundaries for the Fire Protection system. On Drawing D-02301-LR, Foam hose station/hose reel AFFF-HR1 is shown out of scope. Please justify this hose station/hose reel as out of scope.

RAI 2.3.3.15-4 Response The CLB requires an automatic Aqueous Film Forming Foam (AFFF) System meeting the requirements of National Fire Protection Association (NFPA)-1 1B to protect the fuel tank bunkers. The CLB also requires two AFFF portable concentrate stations, one to be located in the DG Building and the other in the yard area for the purpose of combating fires in the day tanks, auxiliary boiler, etc. Each portable station provides 20 minutes of AFFF. The two portable AFFF concentrate stations satisfy the licensing commitment.

The piping portion of the AFFF System is in scope up to the hose reel isolation valve to maintain system integrity. Fixed foam station AFFF-HR1 is shown correctly as out of scope for License Renewal.

NRC RAI 2.3.3.15-5 UFSAR Section 9.5.1.4.1.4 discusses the water fire protection system, including the fixed manual suppression system foam-water hose stations located in the diesel generator building to provide backup suppression for the four-day tank rooms and the oil bath air filters. In UFSAR Section 9.5.1.5, the specific fire hazards analysis for fire zone DG-16 Fan Room states: 'Manual fire fighting should not be difficult. Water standpipes and foam standpipes are provided to assist in manual fire fighting." LRA Section 2.3.3.15 references drawing D-02302-LR for license renewal scoping boundaries for the Fire Protection system. On Drawing D-02302-LR, Foam hose station/hose reels AFFF-HR2 and AFFF-HR-3 are shown out of scope. Please justify these hose station/hose reels as out of scope.

RAI 2.3.3.15-5 Response The CLB requires an automatic AFFF System meeting the requirements of NFPA-11B to protect the fuel tank bunkers. Fire Protection commitment number AF-003 requires an AMFF System and oil retaining system be added to the oil air intake filters. AFFF-HR2 and AFFF-HR3 are

BSEP 05-0050 Page 39 of 87 manual systems and therefore not a fire protection commitment. As such, foam hose stations AFFF--HR2 and AFFF-HR3 are correctly shown out of scope.

The piping portion of the AFFF System is in scope up to the hose reel isolation valve to maintain system integrity.

NRC RAI 2.3.3.15-6 UFSAR Section 9.5.1.4.1.4 discusses the water fire protection system, including the electric motor driven fire pump (P-2), the diesel engine driven fire pump (P-i) and the two jockey pumps (P-3 and P4) providing water for fire suppression and fire fighting. UFSAR Section 9.5.1.4.1.5 discusses the instrumentation and control of the water supply, including the jockey pumps and the electric motor driven pump and diesel engine driven pump. LRA Section 2.3.3.15 references drawing D-04106-LR for license renewal scoping boundaries for the Fire Protection system. On Drawing D-04106-LR, it is unclear if the Control Panels for Pumps P-1 (Engine Driven Fire Pump), P-2 (Motor Driven Fire Pump), P-3 (Jockey Pump), and P-4 (Jockey Pump) are in scope.

Please clarify the status of these control panels, and justify exclusion if they are out of scope.

RAI 2.3.3.15-6 Response Electrical panels for Fire Pumps P-I (i.e., Engine Driven), P-2 (i.e., Motor Driven) and P-3/P-4 (i.e., jockey) are in scope. The electrical enclosures are shown as managed commodities on Table 3.5.2-14 of the application.

NRC RAI 2.3.3.15-7 The Brunswick UFSAR Section 9.5.1.4.3.4 discusses propagation/damage control features that are used to prevent the unhindered spread of fire and also to protect equipment from fire exposures. License renewal section 2.3.3.15 states that physical barriers are addressed in the License Renewal review as structural commodities in Section 2.4. Please clarify that the following have been included within the scope of license renewal, or justify the exclusion from the scope of license renewal:

1. Impingement shields installed between exposed cables of redundant trains of safe shutdown equipment when the trains are within 5 feet vertically or 3 feet horizontally of each other.

2. Impingement shields installed between the two fire pumps and between the diesel fire pump fuel tank and the fire pumps. (Discussed in UFSAR Section 9.5.1.5 fire hazard analysis writeup for fire area MWT-1 Makeup Water Treatment)

BSEP 05-0050 Page 40 of 87

3. Flame retardant coatings applied to conduit and cable trays in cable access ways and spreading areas.

4. Fire stops in Cable Trays.

RAI 2.3.3.15-7 Response

1. Impingement shields are addressed within the "Fire BarrierAssembly" and "Sprayed on Coatings" commodity groups. See LRA Tables 2.4.2-6, 2.4.2-7, 2.4.2-9, 2.4.2-10, 2.4.2-11, and 2.4.2-13.

2. Impingement shields installed between the two fire pumps and between the diesel fire pump fuel tank and the fire pumps are addressed within the "Fire Barrier Assembly" commodity group; see LRA Table 2.4.2-13. However, based on a walkdown inspection of the impingement barriers, the "Fire Barrier Assembly" between the diesel fire pump fuel tank and the fire pumps was observed to be masonry block. The LRA Table 3.5.2-14 identifies the material type of the impingement shield as only carbon steel. The Table will be revised to identify the "Fire Barrier Assembly" material type as Carbon Steel and Masonry Block. Both Fire Barrier Assemblies are addressed within the Fire Protection Program and are managed as fire barriers.

3. Flame retardant coatings applied to conduit and cable trays are addressed within the "Fire Barrier Assembly" and "Sprayed on Coatings" commodity groups. See LRA Tables 2.4.2-6, 2.4.2-7, 2.4.2-9, 2.4.2-10, 2.4.2-11, and 2.4.2-13.

4. Fire stops in cable trays are addressed within the "Fire Barrier Assembly" and "Sprayed on Coatings" commodity groups. See LRATables 2.4.2-6,2.4.2-7,2.4.2-9, 2.4.2-10, 2.4.2-11, and 2.4.2-13.

NRC RAI 2.3.3.17-1 The BSEP LRA in section 2.3.3.17 identifies the radioactive floor drain system as being in scope for license renewal because it contains components that are safety related and relied upon to remain functional during and following design basis events, components which are non-safety related whose failure could prevent satisfactory accomplishment of the safety related functions and components that are part of the Environmental Qualification Program. The LRA includes piping that provides a pressure boundary function and structural support/seismic integrity function. Drawing D-02543-LR, Sheet 1B shows dirty radiological waste (DRW) drain piping at Location E-8, which receives fluid from in-scope drains on the 80' elevation and connects to the in-scope 6" DRW drain to the RHR sump. The DRW drain piping is not identified as being in-scope, even though it is connected to in-scope piping. Provide additional information and justify your determination to exclude the DRW piping at Location E-8 from the scope of license renewal.

RAI 2.3.3.17-1 Response

BSEP 05-0050 Page 41 of 87 The subject piping is within the Radioactive Floor Drains System License Renewal scoping boundary and subject to an aging management review in accordance with 10 CFR 54.4(a)(2).

NRC RAI 2.3.3.17-2 The BSEP LRA in section 2.3.3.17 identifies the radioactive floor drain system as being in scope for license renewal because it contains components that are safety related and relied upon to remain functional during and following design basis events, components which are non-safety related whose failure could prevent satisfactory accomplishment of the safety related functions and components that are part of the Environmental Qualification Program. On drawing D-02533-LR, Sheet 2, at Locations B-8 and C-8, for the lines identified below, the transition locations from out of scope to in-scope is inconsistent with the continuation drawings indicated.

If portions of these lines are out-of-scope for license renewal, their failure may affect the ability of the system to maintain its design function. Provide additional information to clarify the exact locations of these transition points to show clearly which sections are in-scope and which are out-of-scope for license renewal.

1-G16-507-4-160 (D25043-1B, C-8) 1-G16-510-2-160 (D25046, C-1) 1-G16-511-2-160 (D25046, C-8) 2-G16-507-4-160 (D2543-1B, C-8) 2-G16-511-2-160 (D2546, C-8)

RAI 2.3.3.17-2 Response Lines 1-G16-503-3-160 and 2-G16-503-4-160, on drawing D-02533-LR, Sheet 2, support the function of detecting leakage from the RCPB in accordance with Regulatory Guide (RG) 1.45.

(See LRA page 2.3-77.) The connected piping and floor drain collection tank, highlighted on drawing D-02533-LR, Sheet 2, at Locations B-8 and C-8, were credited in the seismic stress analysis for RG 1.45 compliance. See the response to RAI 2.3.3.17-3 for additional information.

Additionally, the portion of 1/2-G16-507 and 511 and 1-G16-510 in the Reactor Building as well as in the radwaste pipe tunnel in the vicinity of safety related SW valves are non-safety related components, which by virtue of their location, may cause adverse spatial interactions with safety related components and, therefore, are within the scoping boundary.

NRC RAI 2.3.3.17-3 The BSEP LRA in section 2.3.3.17 identifies the radioactive floor drain system as being in scope for license renewal because it contains components that are safety related and relied upon to remain functional during and following design basis events, components which are non-safety related whose failure could prevent satisfactory accomplishment of the safety related functions and components that are part of the Environmental Qualification Program. LRA Table 2.3.3.3-14, "Component/Commodity Groups Requiring Aging Management Review and Their

BSEP 05-0050 Page 42 of 87 Intended Functions for the Radioactive Floor Drain System", identifies pump casing and floor drain tank as in-scope. On drawing D02533-LR, Sheet 2, at Location B-5, the line (213-4-161, 240-4-160) from the floor drain collector tank to the suction of the floor drain collector pump is not identified as in-scope for license renewal. In addition, several other lines (234-6-160 at D-8, V71 to Radwaste Bldg wall, 528-3-160 at C-7, 532-3-160 at A-7 and 2-G16-958-3-160 at C-7, 223-6-160, 250-3-160) leading to and from the drain tank are not included as in-scope for license renewal. Failure of these lines could cause loss of the pressure retaining boundary function.

Provide additional information and justify your determination to exclude these lines and the floor drain collector pump casing from the scope of license renewal.

RAI 2.3.3.17-3 Response The Floor Drain Collection Tank, 2-G16-A006, on drawing D-02533-LR, Sheet 2, at Location B-5,was credited in the seismic stress analysis supporting the function of detecting leakage from the RCPB in accordance with RG 1.45. The tank and subject piping is associated with the Liquid Waste Processing System described in LRA Section 2.3.3.24. As shown on LRA Table 2.3.3-19, tanks in the Liquid Waste Processing System have been assigned the M-1 intended function, "Provide pressure-retaining boundary." BSEP methodology typically assigned the M-1 component intended function to pressure retaining mechanical components designated in the EDB as non-safety whose failure could impact a safety function. While the M-4 function designation may have been more appropriate for the Floor Drain Collection Tank, the M-1 function designation is conservative; and applicable aging management reviews are directed towards maintaining pressure boundary integrity. The portions of 2-G16-528/532-3-160 credited in the seismic analysis are in-scope and appropriately highlighted on drawing D-02533-LR, Sheet 2. The remaining non-safety piping and components noted in RAI 2.3.3.17-3 are not included in the seismic analysis terminating at 2-G16-A006 and, therefore, have no intended function.

NRC RAI 2.3.3.18-1 The BSEP LRA in section 2.3.3.18 identifies the radioactive equipment drain system as being in scope for license renewal because it contains components that are safety related and relied upon to remain functional during and following design basis events, components which are non-safety related whose failure could prevent satisfactory accomplishment of the safety related functions and components that are part of the Environmental Qualification Program. LRA Table 2.3.3.3-15, "Component/Commodity Groups Requiring Aging Management Review and Their Intended Functions for the Radioactive Equipment Drains System", identified the equipment drain tank as in-scope because it provides a pressure retaining boundary function. On drawings D-25043-LR, Sheet 1A and D-02543-LR, Sheet 1A, at Location A-7, the equipment drain tank shows several lines entering (8" CRW drain, 6" CV-FO1, 2" 1-160) and two exiting (4" CRW vent and 524-3-161 at A-7) that are not within the license renewal boundary. Failure of any of these lines could negate the pressure retaining boundary function of the equipment drain tank.

Provide additional information and justify your determination to exclude these lines from the scope of license renewal.

BSEP 05-0050 Page 43 of 87 RAI 2.3.3.18-1 Response The Clean Radwaste (CRW) piping described in the Radioactive Equipment Drains System collects treated water from equipment leak-off for transfer to the Radwaste System. The BSEP 10 CFR 54.4(a)(2) scoping methodology allows for the exclusion from applicability of non-safety piping and components that are not normally liquid or steam-filled during operation (e.g.

normally empty pipe) with a low probability of failure during actual use. Based on these considerations and operating experience, normally empty, unpressurized, non-safety CRW piping and components do not present a spatial interaction hazard for safety related components.

The Equipment Drain Tanks and connected piping, shown on drawings D-02543-LR, Sheet IA, and D-25043-LR, Sheet IA, illustrate this scoping approach. The Equipment Drain Tanks are normally partially filled with an overflow that vents to the atmospheric pressure Radioactive Floor Drain System through 1/2-G16-524-3-161, which has no intended function. The piping exiting the Equipment Drain Tanks and connecting to the equipment drain pumps, 1/2-G16-C007, is normally liquid-filled and within the License Renewal scoping boundary. The piping down stream of the Equipment Drain Pump is normally liquid filled, can be pressurized and is within the License Renewal scoping boundary. The only lines entering the top of the Equipment Drain Tanks shown as in-scope for License Renewal is the return line from the Equipment Drain Tank cooling heat exchanger, 1/2-G16-B002, which was conservatively assumed to be liquid-filled and pressurized.

In summary, the portion of the Radioactive Equipment Drains System marked, on D-02543-LR, Sheet IA, and D-25043-LR, Sheet 1A at Location A-7, as being within the License Renewal scoping boundary is for compliance with 10 CFR 54.4(a)(2).

NRC RAI 2.3.3.18-2 The BSEP LRA in section 2.3.3.18 identifies the radioactive equipment drain system as being in scope for license renewal because it contains components that are safety related and relied upon to remain functional during and following design basis events, components which are non safety related whose failure could prevent satisfactory accomplishment of the safety related functions and components that are part of the Environmental Qualification Program. Drawing D-25043-LR, Sheet IA, at Location E-5, shows a portion of drain piping as being within the scope of license renewal. However, the Clean Radioactive Waste (CRW) line that it flows into to return to the equipment drain tank is not shown as being in scope. Failure of this piping could prevent the equipment drain piping from performing its intended function. Provide additional information to justify your determination to exclude this piping from the scope of license renewal. Also, the same drain line shown on Unit 2 drawing D-02543-LR, Sheet lA, at Location E-4, is not in scope for license renewal. Provide rationale as to why the same drain line on Unit 2 is not in-scope.

BSEP 05-0050 Page 44 of 87 RAI 2.3.3.18-2 Response The piping connected to hub-drain, C45HD, on drawing D-25043-LR, Sheet IA, at Location E-5 was marked in error as being within the License Renewal scoping boundary. This piping is normally empty, unpressurized, non-safety CRW piping with no intended function. The corresponding Unit 2 components are correctly represented on D-02543-LR, Sheet IA.

Information provided in response to RAI 2.3.3.18-1 provides a more complete discussion of 10 CFR 54.4(a)(2) scoping evaluations for the Radioactive Equipment Drains System.

NRC RAI 2.3.3.18-3 The BSEP LRA in section 2.3.3.18 identifies the radioactive equipment drain system as being in scope for license renewal because it contains components that are safety related and relied upon to remain functional during and following design basis events, components which are non-safety related whose failure could prevent satisfactory accomplishment of the safety related functions and components that are part of the Environmental Qualification Program. Drawing D-02531-LR, Sheet 1, at Location C-7, shows the waste collector tank as being within scope because it provides a pressure boundary function. There are several lines that exit the tank that are not included as in-scope for license renewal. These lines should be in-scope at least to the nearest isolation valve. Failure of these lines could negate the pressure boundary function of the waste collector tank. Provide additional information and justify your determination to exclude the following piping and associated isolation valves from the scope of license renewal.

Line 14-4-161 and valve F036 Line 35-4-161 and valve F033, F141 Line 677-1/2-161 and its first isolation valve Line 2G41-59-8-154 Instrument level transmitter N026 and valve V338 Waste Collector Pump suction line 1-4-152 and valves F034 Line 9-8-160 and 2" CDW/SCRD cap RAI 2.3.3.18-3 Response The Waste Collection Tank, 2-G16-A002, on drawing D-02531-LR, Sheet 1, at Location C-7,was credited in the seismic stress analysis as supporting the function of detecting leakage from the RCPB in accordance with RG 1.45. The tank and subject piping is associated with the Liquid Waste Processing System described in LRA Section 2.3.3.24. As shown on LRA Table 2.3.3-19, tanks in the Liquid Waste Processing System have been assigned the M-1 intended function, "Provide pressure-retaining boundary." BSEP methodology typically assigned the M-1 component intended function to pressure retaining mechanical components designated in the EDB as non-safety whose failure could impact a safety function. While the M-4 function designation may have been more appropriate for the Waste Collection Tank, the M-1 function designation is conservative and applicable aging management reviews are directed towards maintaining pressure boundary integrity. The Waste Collection Pump suction line, 2-G16-14-152, and isolation valve, 2-G16-F034, are within the system scoping boundary and

BSEP 05-0050 Page 45 of 87 should have been highlighted on drawing D-02531-LR, Sheet 1. The remaining non-safety piping and components noted in RAI 2.3.3.18-3 are not included in the seismic analysis terminating at 2-G16-A002 and, therefore, have no intended function.

NRC RAI 2.3.3.19-1 BSEP LRA Table 2.3.3-16 identifies the intended function for Demineralized Water System tank (shell) components requiring aging management review as Ml provide pressure-retaining boundary. BSEP license renewal boundary drawings D-02040-LR Sheet IA at Quadrant C-6 and D-02040-LR Sheet 1B at quadrant C4 show the Unit 1 and Unit 2 Condensate Storage Tank (CST) shells as in-scope for license renewal. Some of the following Unit 1 and Unit 2 condensate storage tank shell nozzle locations are connected non-isolable portions that are shown as not in-scope for license renewal and some are isolable but the piping is shown as not in-scope up to and including the first isolation valve:

CST nozzle -15 D-02040-LR Sheet 1A Quadrant C-5 and D-02040-LR Sheet 1B Quadrant C-5 CST nozzle -5 D-02040-LR Sheet 1A Quadrant C-5 and D-02040-LR Sheet LB Quadrant C4 CST nozzle -2 D-02040-LR Sheet IA Quadrant C-6 and D-02040-LR Sheet LB Quadrant C-4 CST nozzle -9 D-02040-LR Sheet IA Quadrant C-6 and D-02040-LR Sheet LB Quadrant C-4 CST nozzle -13, D-02040-LR Sheet LA Quadrant C-7 and D-02040-LR Sheet LB Quadrant C-3 CST nozzle -8 D-02040-LR Sheet LA Quadrant C-7 and D-02040-LR Sheet LB Quadrant C-3 CST nozzle -14 D-02040-LR Sheet LA Quadrant C-7 and D-02040-LR Sheet LB Quadrant C-3 CST nozzle -3 D-02040-LR Sheet LA Quadrant C-7 and D-02040-LR Sheet LB Quadrant C-3 CST nozzle 4 D-02040-LR Sheet LA Quadrant C-7 and D-02040-LR Sheet LB Quadrant C-3 CST nozzle -6 D-02040-LR Sheet IA Quadrant C-7 and D-02040-LR Sheet LB Quadrant C-3 Failure of the non-isolable piping connected to the above CST shell nozzles could result in a loss of the tank shell pressure-retaining function. Please provide additional information justifying the in-scope boundaries selected for the non-isolable piping connected to the above CST shell nozzles.

RAI 2.3.3.19-1 Response The CSTs are non-safety related, located in the yard and in the scope of License Renewal under 10 CFR 54.4(a)(3), for compliance with Station Blackout (SBO) requirements. UFSAR

BSEP 05-0050 Page 46 of 87 Section 9.2.6.2 describes the configuration of the CST, specifically identifying 12 inch and 16 inch piping with connection centerlines to the tank at the 10 foot level that preserve the inventory below that point for use by the High Pressure Coolant Injection (HPCI) and Reactor Core Isolation Cooling (RCIC) systems. The UFSAR notes that the physical arrangement of the tank and associated piping assures a reserve capacity of 74,000 gallons, and that additional reserve capacity is provided by an administrative limit at the 10 foot level to provide a total HPCI/RCIC reserve inventory of 105,700 gallons. The NRC Safety Evaluation Report (SER) for SBO compliance notes that the 10 foot level assures an inventory greater than 103,380 gallons, and is therefore sufficient for the coping duration. A review of the BSEP Extended Power Uprate (EPUR) submittal confirms that these limits were not affected by uprated power conditions.

Based on these considerations, BSEP is including piping connected to the Unit 1 and 2 CSTs at or below the 10 foot level in the scope of License Renewal. In addition to piping connected to nozzles N-I and N-12, which are already in scope, this includes the following connected piping up to their first isolation valves:

Condensate transfer pump suction line connected to nozzle N-2, CRD pump condensate return line connected to N-3, Condensate supply line connected to nozzle N-9, Unit 1 and 2 CST cross-connect lines connected to nozzles N-8 and N-13, HPCI/RCIC test return line connected to nozzle N-14, and Drain line connected to nozzle N-5.

The tank volume above the 10 foot level is not needed for compliance with SBO, and piping connected above this point does not satisfy any license renewal scoping criteria.

The piping and equipment included in license renewal scope, as identified above, will be managed internally with the Water Chemistry and the One-Time Inspection Programs, and externally with the Systems Monitoring and Buried Piping and Tanks Inspection Programs.

NRC RAT 2.3.3.19-2 BSEP LRA Table 2.3.3-16 identifies the intended function for MWTS piping components requiring aging management review as MI provide pressure-retaining boundary. BSEP license renewal boundary drawing D-25043-LR Sheet IA at Quadrants F-4 and F-5 identifies a common drain header and selected connecting RWCU drain piping as in-scope for license renewal. For two RWCU drain lines, the in-scope boundary extends to piping shown on drawing D-25028-2B at Quadrants B-2 and B-6. Drawing D-25028-2B is not identified in LRA Section 2.3.3.19 as a MWST boundary drawing for license renewal. In addition this drawing was not made available for staff review. This is inconsistent with license renewal boundary drawing D-02543-LR Sheet IA at Quadrants F-4 and F-5 which shows these piping as not in-scope. Please provide additional information to explain these inconsistencies and the basis for the boundary determinations.

BSEP 05-0050 Page 47 of 87 RAI 2.3.3.19-2 Response The above-referenced common drain header to C45HD, and connecting RWCU drain piping to D-25028-2B shown on D-25043-LR, Sheet 1A at Location F4, F-5 are not in scope and were inadvertently highlighted.

NRC RAI 2.3.3.24-1 The BSEP LRA in section 2.3.3.24 identifies the Liquid Waste Processing system as being in scope for license renewal because it contains components that are non-safety related whose failure could prevent satisfactory accomplishment of the safety related functions and components that are relied upon during postulated fires. LRA Table 2.3.3.3-19, "Component/Commodity Groups Requiring Aging Management Review and Their Intended Functions for the Liquid Waste Processing System", identified tanks as in-scope because they provide the pressure boundary function. There are four waste neutralizer tanks and the concentrated waste tank in the liquid waste system. Drawing D-02534-LR, sheet 1, at Locations E-3 and E-5, shows waste neutralizer tanks A and C, respectively. Drawing D-02534-LR, Sheet 2, at Locations E-4 and E-6, show waste neutralizer tanks B and D, respectively. Drawing D-02492-LR, at Location B-3, shows the Concentrated Waste Tank. Several lines identified below, enter each tank and they are not in-scope for license renewal. Failure of any of these lines would negate the pressure boundary function of the liquid waste system. Provide additional information and justify your determination to exclude the lines up to the closest isolation valve from the scope of license renewal.

"A" Waste Neutralizer Tank Line 297-6-161 and valves F224A, V1379 Line 302-3-Z-5 and valve, V14A, F231A, V1086 Line 338-8-161 Line 2924-161, valve F222A Line 337-8-161 (cross tie between A & C tanks)

"C" Waste Neutralizer Tank Line 291-4-161, valve F222C Line 296-6-161, valve F224C Line 301-3-Z-5, valves V14C, V13C, F231C Line 336-8-161 "B" Waste Neutralizer Tank Line 299-6-161, valve F224B Line 304-3-Z-5, valves V14B, V13B, V1087, and F231B Line 338-8-161 Line 292-4-161, valve F222B Line 339-8-161 (cross tie between B & D tanks)

BSEP 05-0050 Page 48 of 87 "D" Waste Neutralizer Tank Line 293-4-161, valve F222D Line 296-6-161, valve F224D Line 303-3-Z-5, valves V14D, V13D, F231D Line 336-8-161 Concentrated Waste Tank Drawing Line 997-2-162 Line 353-1-1/2-162, valve F281 Line 355-3-160 Valve V5019 RAI 2.3.3.24-1 Response The stainless steel waste neutralizer tanks, 2-G16-AO25A/B/C/D, on drawings D-2534-LR, Sheets 1 and 2, and concentrated waste tank, 2-G16-A026, on drawing D-02492-LR are non-safety related components in the Liquid Waste Processing system. BSEP conservatively brought these tanks into the scope of License Renewal on the basis of their being seismically analyzed to assure continued function during an earthquake. A review of the licensing basis of these tanks shows BSEP agreed to seismic design with the Atomic Energy Commission/Division of Reactor Licensing during evaluation of the Radwaste System design against 10 CFR 20 limits, and that their failure would not result in exceedance of 10 CFR 100 limits or adversely impact any safety related function. The License Renewal boundaries reflected in the BSEP License Renewal Boundary Drawings are limited to the tanks and connected piping included in the seismic design, consistent with the design and licensing basis.

NRC RAI 2.3.3.26-1 The BSEP UFSAR Section 9.1.3.3 states that there are non seismic drain connections located in the refueling canal between the fuel pool inner gate and the barrier that could drain the fuel pool below the top of the stored fuel if a seismic event occurred when the fuel pool gates are removed for refueling. Plugs are installed in these drain connections during refueling to prevent loss of water below the elevation of the top of the barrier after a seismic event. The BSEP LRA Section 2.3.3.26 states that components that are safety related and are relied upon to remain functional during and following design basis events are in the scope of license renewal.

However, the drain lines in question, G41-75-1-1/2-161, G41-108-3-161, 111-1-1/2-161, 107-1-1/2-161, and 82-1-161, shown on drawings D-25049, Sheet IB, at Location D-4 and D-02549 Sheet 1B, at Location D-4 respectively, are not identified as being in scope for license renewal. Failure of these drain lines and associated valves could cause loss of refueling pool water during refueling preventing the fuel pool cooling system from maintaining adequate level and temperature in the spent fuel pool. Provide additional information and justify your determination to exclude these sections of drain piping from the scope of license renewal.

BSEP 05-0050 Page 49 of 87 RAI 2.3.3.26-1 Response As noted in USFAR Section 9.1.3.3, the design of the fuel pool places the top of the stored fuel at a lower elevation than the top of the barrier located between the reactor well and the fuel storage pool. However, non-seismic drain connections located in the refueling canal between the fuel pool inner gate and the barrier could drain the fuel pool below the top of the stored fuel if a seismic event occurred when the fuel pool gates are removed for refueling.

Because the subject lines are non-safety and not seismically designed, plugs are installed into G41-75-1-1/2-161 and G41-108-3-161 during refueling to prevent the loss of fuel pool water below the elevation of the top of the barrier after a seismic event. G41-111-1-1/2-161, in each unit, is on the vessel side of this barrier and drain well above the required level. There is a baffle on top of the barrier between G41-75-1-1/2-161 and G41-111-1-1/2-161 that ensures the fuel pool water level is adequate without plugging of G41-111-1-1/2-161. G41-82-1-161 is a 1-inch stainless steel leak-off monitoring line entirely imbedded in concrete that drains back into fuel pool leak-off monitoring. Even if these non-safety drain lines were to experience age related degradation, no loss of intended function would occur. BSEP 10 CFR 54.4(a)(2) scoping methodology allows for the exclusion from applicability of non-safety piping and components that are not normally liquid or steam filled during operation (e.g., normally empty pipe) with a low probability of failure during actual use. Based on operating experience, normally empty, non-safety Refueling System piping and components do not present a spatial interaction hazard for safety related components.

NRC RAI 2.3.3.33-1 The Civil Structure Auxiliary systems are not described in the BSEP UFSAR. The BSEP LRA states that Civil Structures Auxiliary Systems are in scope of license renewal because they contain either or both of the following:

1. Components that are safety-related and are relied upon to remain functional during and following design basis events,

2. Components which are nonsafety-related whose failure could prevent satisfactory accomplishment of the safety-related functions.

Table 2.3.3-24 Component Commodity Groups requiring aging management review and their intended functions identifies several components and commodity groups that are in scope for license renewal; however there are no license renewal drawings available to determine if the list is complete. Provide additional clarifying information to allow for a determination that the appropriate Civil Structure Auxiliary systems have been included within the scope of license renewal.

BSEP 05-0050 Page 50 of 87 RAIT 2.3.3.33-1 Response The components noted in the Civil/Structural Auxiliary system are comprised of miscellaneous EDB entries, of a mechanical type, without a corresponding system designation or piping and instrument drawing (P&ID). For the most part, the subject plant equipment is identified in EDB as associated with a structure so that it can be referenced for a maintenance activity. The Civil/Structural Auxiliary system components identified as within the scope of License Renewal provide a mechanical function in support of a structure (e.g., sump pumps for a building). All pressure retaining mechanical components associated with these Civil/Structural Auxiliary systems were included in Table 2.3.3-24.

NRC RAIT 2.3.4.5-1 The BSEP UFSAR states that the feedwater system is to provide a dependable supply of feedwater to the reactor and to provide feedwater heating. Drawing D-25021-LR, Sheet iC, Locations B-7 and C-7 and drawing D-02521-LR, Sheet IC, Locations B-8 and C-8 have LRA flags in the middle of a section of pipe. The BSEP LRA Table 2.3.4-3 states that piping, fittings and valves are in scope. Failure of this section of pipe could have an effect on the Intended Function M-1, provide pressure retaining boundary. Explain how the LRA boundary can occur in the middle of a section of pipe.

RAI 2.3.4.5-1 Response Failure of the referenced portion of the non-safety related Feedwater System lines, shown on drawing D-25021-LR, Sheet IC, Locations B-7 and C-7, and drawing D-02521-LR, Sheet 1C, Locations B-8 and C-8, have been evaluated. The evaluation was performed as part of the stress analysis of the interface between the non-safety related Feedwater System piping boundary shown with the License Renewal flag and the piping boundary at the safety related F032A/B Outside Containment Isolation Valves which are part of the Reactor Vessel and Internals System.

The intended function of M-1 was conservatively chosen for this portion of the Feedwater System piping. The License Renewal boundary flag is shown correctly on drawings D-2502 1-LR, Sheet I C, and D-02521-LR, Sheet IC.

The subject Unit 1 and Unit 2 non-safety related Feedwater piping is in scope since it is seismically analyzed, connected to safety related Reactor Vessel and Internals System components, and could have spatial interactions with safety related components. Failure of Feedwater piping outside the License Renewal boundary flag has been evaluated and will not affect the safety related intended function of Reactor Vessel and Internals System components.

The BSEP scoping methodology included piping as in-scope where piping failure could affect nearby safety related components through spray, falling down, or being seismically connected.

The subject in-scope Feedwater piping is seismically connected but is also located in the Reactor Building and, therefore, cannot be allowed to spray or fall on safety related components in the Reactor Building. The intended function of M-1 for the subject in-scope Feedwater System piping was conservatively chosen to provide an aging management program for both the piping internal and external surface. ISG-9 recommends that if the in-scope connected non-safety

BSEP 05-0050 Page 51 of 87 related component is of a similar material/environment combination, a similar aging management program should be applied for the connected safety related component. For the subject piping, similar aging management programs were chosen as those of the connected safety related Reactor Vessel and Internals System components. In summary, the License Renewal boundary flag is shown correctly on D-25021-LR, Sheet 1C, and D-02521-LR, Sheet 1C, with a pressure boundary mechanical intended function.

NRC RAI 2.3.4.7-1 The BSEP UFSAR Section 3.4.2.6 states that various flood level alarms in the circulation water condenser pits warn the operator that an abnormal condition exists and that water is entering the pit. The USFAR further states that a set of three level alarms installed 9 feet above the pit floor will, when activated, automatically shut off the circulating water pumps. In light of the fact that the main condenser will not be designated to serve as a pressure-retaining boundary for license renewal, provide additional information to address whether any safety related equipment or equipment that supports a safety function could be affected by flooding in this area.

RAI 2.3.4.7-1 Response A review of flood susceptibility noted that the failure of the expansion joints in the circulating water condenser pits had the potential to result in the automatic shutdown of both reactors, and non-safety related leak detection equipment was installed in the condenser pits to address this concern. While such a failure might represent a challenge to safety related equipment, it would not impair any safety related function and is not the basis for including SSCs in the scope of License Renewal.

NRC RAI 2.3.4.11-1 The BSEP LRA section 2.3.4.11 states that the Turbine Generator LO System is in the scope of License Renewal because it contains components which are nonsafety-related whose failure could prevent satisfactory accomplishment of safety-related functions. The BSEP UFSAR, section 10.2.2 states that the Turbine Generator interlocks and features necessary to maintain system integrity, such as those for lube oil pressure, seal oil pressure, and back pressure are similar to those used in conventional turbine generator systems. The BSEP UFSAR, section 10.2.4.b also describes the testing necessary to maintain safe operation of the Turbine Generator including tests on the lube oil system oil tank high low level alarm system. The function of the turbine generator lube oil system is to supply all the necessary lubricating oil to the main turbine and its support systems to allow the turbine to operate properly. The system is required to be in service during startups, normal operations, shutdowns, and any time the turbine is on the turning gear. Although not a requirement, previous BWR license renewal applicants (Dresden Quad Cities SER) have highlighted those portions of the turbine generator lube oil system within scope on reference P&I drawings. Also, previous BWR applicants have identified the following component groups and their intended functions within the turbine generator lube oil system as being within the scope of license renewal and subject to and AMR:

BSEP 05-0050 Page 52 of 87 closure bolting (pressure boundary) filters/strainers (spatial interaction) piping and fittings (spatial interaction) piping and fittings (structural integrity/attached support) pump casings (spatial interaction) tanks (spatial interaction) valves (spatial interaction) valves (structural integrity/attached support)

The BSEP LRA section 2.3.4.11 states that the Turbine Generator LO System components that are subject to AMR are addressed as civil commodities in section 2.4 with no clarifying information provided. No listing of components similar to that above was provided and no reference P&I drawings were provided. Without additional information and a more detailed description of the Brunswick turbine generator lube oil system functions, it can not be confirmed that all turbine generator lube oil system components within the scope of license renewal and subject to an AMR have been properly identified. Provide additional information and justification to confirm that all turbine generator lube oil system components within the scope of license renewal and subject to an AMR in accordance with 10 CFR 54.4 and 10 CFR 54.21(a)(1) have been identified.

RAI 2.3.4.11-1 Response The Turbine Generator Lube Oil (LO) System supplies lubricating oil for proper operation of the Main Turbine. However, operation of the Main Turbine is not necessary to support any intended function for License Renewal.

The Turbine Generator LO System was determined to be in scope of License Renewal based on the quality classifications of a few electrical control switches located in the vicinity of safety related components. The entire Turbine Generator LO System is non-safety related; however, the active electrical switches that bring it into scope must be seismically analyzed to prevent undesirable interactions with safety related equipment. The supports for components having this quality classification are within the scope of License Renewal as civil commodities. Refer to the electrical enclosure commodity listed on LRA Table 2.4.2-10.

The 10 CER 54.4(a)(2) review at BSEP determined that the pressure boundary components and commodities of the Turbine Generator LO System are not in scope of License Renewal either for potential spatial interactions with in scope equipment or for providing support for the seismically analyzed portions of in-scope systems.

NRC RAI 3.2-1 In LRA Table 3.2.2-1, carbon steel spray nozzles in the drywell and suppression chamber spray system, in a dry air/gas (internal) environment, are not identified with any aging effects. The applicant states that the basis is that "Suppression pool spray is not required for design basis

BSEP 05-0050 Enclosure I Page 53 of 87 events. Drywell spray nozzles/piping is required but is normally isolated and not subject to plugging or fouling." Provide an explanation of why the suppression pool spray is not required for design basis events. Provide also the procedure taken to ensure that drywell spray nozzles/piping will be free from plugging. It should be noted that industry operating experience has revealed that plugging or fouling, which results in flow blockage of carbon steel spray nozzles, could occur if not properly prevented or managed.

RAI 3.2-1 Response The Drywell and Suppression Pool Spray subsystems are provided to condense steam and cool non-condensable gases in reducing containment pressure and temperature after a Loss of Coolant Accident (LOCA). Analyses performed in support of the BSEP EPUR submittal credit containment (i.e., Drywell) spray with maintaining the drywell temperature profile within EQ requirements subsequent to small steamline breaks. Otherwise, neither drywell nor suppression pool spray is needed to maintain post-accident primary containment pressure/temperature parameters within acceptable values.

The assumption that drywell spray nozzles and piping are free from plugging is not based on procedural requirements, but rather on consideration that drywell spray components are not intermittently wetted, that the drywell is inerted with nitrogen during operation, and that the spray nozzles themselves are constructed of corrosion resistant material (i.e., brass).

The industry operating experience discussed in NUREG-1800, Section 3.2.2.7, pertains to spray piping that is subject to alternate wetting, and is not applicable to Drywell Spray components at BSEP. Drywell Spray is a post-accident function at BSEP. It is not actuated during the course of normal plant operations, and UFSAR 5.4.7.4 notes that operation of the valves to the containment spray headers is checked by operating the upstream and downstream valves individually, thereby avoiding initiating spray during routine testing.

NRC RAI 3.2-2 In LRA Table 3.2.2-2, no aging effects are identified for glass components in a treated water (internal) environment. Provide the basis for such determination.

RAI 3.2-2 Response Because most silicate glasses have a high resistance to corrosion in normal environments, glass per se is frequently considered to be an inert substance. Silica is almost insoluble in an aqueous environment except at temperatures in excess of 4820F. Acid attack of soda-lime and bororsilicate glass compositions is minimal due to the formation of protective, highly siliceous surface layer, except for hydrofluoric and phosphoric (i.e., at high temperatures) acids. Indoor and outdoor environments do not typically contain contaminants that could concentrate and chemically attack glass. No definitive instances of glass failure due to aging have been

BSEP 05-0050 Enclosure I Page 54 of 87 identified in BSEP or industry operating experience searches. Therefore, no aging effects are predicted for glass components in the Containment Atmospheric Control System.

NRC RAI 3.2-3 In LRA Table 3.2.2-2, for the stainless steel heat exchangers in dry air/gas (internal) environments, the applicant stated under Note 208 that "Heat exchangers in this category are in scope for spatial interaction with safety related components. Therefore, only the external surfaces require aging management review." Clarify what this statement means, and explain how the aging management for the "spatial interaction" of the stainless steel components is to be performed.

RATI 3.2-3 Response "Spatial interaction" in the context of Note 208 means the potential to spray, wet, or otherwise adversely affect the function of safety related equipment. In this instance, the heat exchangers are sample precoolers, which are literally coils in an air environment. Since the application does not involve liquid filled components, Note 208 was misapplied. Notes 221 and 215 are applicable, and no aging effects are predicted.

NRC RAIT 3.2-4 In LRA Tables 3.2.2-3 and 3.2.2-5, and 3.2.2-7, carbon and stainless steel small-bore piping and fittings less than NPS 4-inch diameter, in treated water (includes steam)(internal) environments, are subject to cracking due to thermal and mechanical loading. The Section XI Inservice Inspection and Water Chemistry Programs are credited to manage the aging effects. In the subject tables, stainless steel small-bore piping less than NPS 4-inch diameter, in the same environment of treated water (includes steam )(internal), are also subject to cracking due to SCC.

The same AMPs are credited to manage the aging effect. The applicant is requested to (1) provide the basis for the statement made under Note 226 that "cracking due to thermal and mechanical loadings was evaluated and dispositioned as not applicable," and (2) clarify the statement made under Note 226 that "The risk associated with cracking due to SCC is bounded by those components selected for inservice inspection as part of the Risk-Informed ISI Program..."

RATI 3.2-4 Response

1) Susceptibility to thermal and mechanical loading has been formally evaluated on a component specific basis based on consideration of materials, temperatures, configuration, etc., in support of the BSEP Risk-Informed Inservice Inspection (RI-ISI) submittal in PEC letter to the NRC, (Serial: BSEP 01-0013), "Brunswick Steam Electric Plant, Unit Nos. I and 2, Docket Nos. 50 325 and 50 324/License Nos. DPR 71 and DPR 62, Third 10 Year Inservice Inspection Program -Request for Approval of Risk Informed Inservice Inspection Program," dated April 20, 2001 (MLO 13320632).

BSEP 05-0050 Page 55 of 87

2)

BSEP has revised its aging management strategy for small-bore piping to include a one-time inspection in response to NRC comments during an audit of Aging Management Programs, and no longer credits RI-ISI in aging management. BSEP credits the Water Chemistry Program and American Society of Mechanical Engineers (ASME)Section XI Subsection IWB, IWC and IWD Program for aging management of cracking, including stress corrosion cracking (SCC), in less than 4-inch Nominal Pipe Size (NPS) Class 1 piping components.

Consistent with NUREG-1801, the One-Time Inspection Program will be used to verify the effectiveness of these programs. This one-time inspection activity is described as follows:

The inspection includes a representative sample of the population, and, where practical, focuses on the bounding or lead components most susceptible to aging due to time in service, severity of operating conditions, and lowest design margin. For small-bore piping, actual inspection locations are based on physical accessibility, exposure levels, Non-Destructive Examination (NDE) techniques, and locations identified in Nuclear Regulatory Commission (NRC) Information Notice (IN) 97-46, as applicable.

Combinations of NDE, including visual, ultrasonic, and surface techniques, are performed by qualified personnel following procedures consistent with the ASME Code and 10 CFR 50, Appendix B. For small-bore piping less than NPS 4 inches, including pipe, fittings, and branch connections, a plant-specific destructive examination of replaced piping due to plant modifications or NDE that permits inspection of the inside surfaces of the piping will be performed to ensure that cracking has not occurred.

Follow-up of unacceptable inspection findings includes expansion of the inspection sample size and locations. With respect to inspection timing, the one-time inspection is to be completed before the end of the current operating license. Inspections may be scheduled in such a way as to minimize the impact on plant operations. However, the inspection is not to be scheduled too early in the current operating term, which could raise questions regarding continued absence of aging effects prior to and near the extended period of operation.

NRC RAI 3.2-5 In LRA Table 3.2.2-3, stainless steel piping and fittings (HPCI) in treated water (includes steam)(intemal) environments are subject to cracking due to SCC. The Water Chemistry and One-Time Inspection Programs are credited to manage the aging effect. The staff noted in LRA Section B.2.15 the statement made by the applicant that "BSEP does not utilize the One-Time Inspection Program activity specified in NUREG-1801, for detection of cracking in small-bore Class 1 piping. Cracking of this piping will be detected and managed by the combination of the ASME Section XI, Subsection IWB, IWC and IWD Program supplemented by the Water Chemistry Program..." Clarify the discrepancy found in the above statement and AMR review commitment.

BSEP 05-0050 Page 56 of 87 RAI 3.2-5 Response BSEP has revised its aging management strategy for small-bore piping in response to NRC comments during an audit of Aging Management Programs for consistency with NUREG-1 801, "Generic Aging Lessons Learned (GALL) Report." BSEP credits a combination of the Water Chemistry Program,Section XI Inservice Inspection, Subsections IWB, IWC and IWD Program, and the One Time Inspection Program for managing cracking of small bore piping, consistent with the recommendations of GALL IV.C.1.13. See the responses to RAI 3.2-4 and NRC Audit Question B.2.15-la for additional information.

NRC RAI 3.2-6 In LRA Table 3.2.2-5, carbon steel piping and fittings (misc. auxiliary and drain piping and valves) in treated water (internal) environments are subject to loss of material due to crevice, general, and pitting corrosion. The One-Time Inspection Program is credited to manage the aging effects. The applicant's Note 205 states that "The One-Time Inspection Program will include elements to verify the integrity of spatial interaction piping." Explain how this note is applicable to the aging effects identified. Provide the basis of using the One-Time Inspection Program alone to manage the identified aging effects without the use of the Water Chemistry Program.

RAI 3.2-6 Response The subject line item should reflect Water Chemistry and One-Time Inspection for aging management. The AMR is being revised to apply these two programs consistent with comparable line items in the Residual Heat Removal (RHR), HPCI, and RCIC Systems.

NRC RAI 3.2-7 In LRA Table 3.2.2-7, carbon steel piping (piping specialties) in treated water (internal) environments is subject to loss of material due to crevice, general, and pitting corrosion. The Preventive Maintenance (PM) Program is credited to manage the aging effects. The applicant's Note 206 states that "Internal inspection of the phenolic-lined carbon steel accumulator tanks is performed under the Preventive Maintenance Program." Explain the discrepancy noted in the types of components being considered in the aging management review. Provide the basis of crediting the Preventive Maintenance Program to manage the identified aging effects, in lieu of the Water Chemistry and One-Time Inspection Programs.

RAI 3.2-7 Response The PM Program is directed at defined inspections of specific components. The SLC hydraulic accumulators are carbon steel tanks lined internally with a phenolic coating, containing a rubber bladder charged with nitrogen. BSEP has existing PM routes to internally inspect these accumulators to verify the integrity of the rubber bladder, the condition of the phenolic coating, and any corrosion occurring on the interior surfaces of the carbon steel tanks. These activities

BSEP 05-0050 Page 57 of 87 provide direct verification on an ongoing basis that aging effects are not occurring. BSEP does credit Water Chemistry with aging management of stainless steel piping and components in the SLC System.

NRC RAI 3.4-1 In LRA Tables 3.4.2-1 and 3.4.2-6, stainless steel piping and fittings (steam drains) and valves in treated water (includes steam)(internal) environments are subject to cracking due to SCC, and loss of material due to crevice and pitting corrosion. The Water Chemistry Program alone is credited to manage the aging effects. This is not acceptable to the staff, since for the BWR plant components in the identified environments, the AMP needs to be augmented by verifying the effectiveness of water chemistry control. The applicant is requested to reassess the aging management review for the components.

RAI 3.4-1 Response Stainless steel components represented by the Table 3.4.2-1 subject line items are non-safety related orifice plates and instrumentation components. Stainless steel components represented by the Table 3.4.2-6 subject line items are non-safety related stainless steel tubing. To verify the effectiveness of water chemistry control for these stainless steel components, the Water Chemistry AMP will be augmented by using the One-Time Inspection Program.

NRC RAI 3.4-2 In LRA Table 3.4.2-2, carbon steel piping and fittings (steam drains) and valves in treated water (includes steam)(internal) environments are subject to loss of material due to general, crevice, and pitting corrosion. The One-Time Inspection Program is credited as the only AMP to manage the aging effects. A one-time inspection program may be appropriate only for situations where material degradation is not expected or is expected to occur at a slow rate. One-time inspections can also be used to verify the effectiveness of an AMP in its management of aging effects.

Provide justification that a periodic inspection program, supplemented by the One-Time Inspection Program, is not used to manage the aging effects for the above carbon steel components. Also confirm that the piping is not a small-bore Class 1 piping, in order for the One-Time Inspection Program to be applicable for crack detection (ref. RAI 3.2-5 and LRA Section B.2.15).

RAI 3.4-2 Response The components represented by the LRA Table 3.4.2-2 subject line items are non-safety related Auxiliary Boiler System piping components and valves in scope for potential spatial interactions.

The piping components are not small-bore Class 1 piping. The Auxiliary Boiler System is a unit-sharing system which provides steam to both Unit 1 and Unit 2 for HPCI and RCIC turbine testing prior to unit startup. This auxiliary steam piping is only used infrequently for unit startup at the HPCI and RCIC turbines located in the Reactor Building. This auxiliary steam piping is

BSEP 05-0050 Page 58 of 87 routed through the Radwaste Building tunnels into the Reactor Building and is shown on License Renewal drawing D-02021-LR. After the IHPCI and RCIC turbines are tested during unit startup, the subject steam supply piping in the tunnels and Reactor Building are de-pressurized and isolated from the Auxiliary Boiler. The subject piping is not under constant water chemistry control, although chemicals are added to the water at the Auxiliary Boiler.

The GALL XI.M32, One-Time Inspection AMP is appropriate for the subject Auxiliary Boiler piping components. As stated in Draft NUREG-1801:

A one-time inspection may be used to provide additional assurance that aging that has not yet manifested itself is not occurring, that the evidence of aging shows that the aging is so insignificant that an aging management program is not warranted. A one-time inspection may also trigger development of a program necessary to assure component intended functions through the period of extended operation.

XI.M32 also states:

However, there may be locations that are isolated from the flow stream for extended periods and are susceptible to the gradual accumulation or concentration of agents that promote certain aging effects. This program provides inspections that either verify that unacceptable degradation is not occurring or trigger additional actions that will assure the intended function of affected components will be maintained during the period of extended operation.

In this case, the One-Time Inspection Program will verify that the expectation of potential aging effects occurring very slowly so as not to affect the component intended function during the period of extended operation is correct or will verify the extent of condition for subsequent corrective actions. This is the approach used at BSEP and, based on the program description in NUREG-1801, is not a deviation from GALL recommendations.

In summary, the subject piping is not small-bore Class 1 piping. The subject in-scope Auxiliary Boiler System piping components and valves are infrequently used, and isolated from the Auxiliary Boiler after usage with piping that is de-energized and drained or partially drained.

The use of the One-Time Inspection AMP is appropriate for the subject Auxiliary Boiler piping components.

NRC RAI 3.4-3 In LRA Tables 3.4.2-3 and 3.4.2-4, stainless steel pipe and fittings (steam drains) and valves in treated water (includes steam)(intemal) are subject to cracking due to SCC and loss of material due to crevice and pitting corrosion. The Water Chemistry and One-Time Inspection Programs are credited to manage the aging effects. Confirm that the piping is not a small-bore Class 1 piping, in order for the One-Time Inspection Program to be applicable for crack detection.

BSEP 05-0050 Page 59 of 87 RAI 3.4-3 Response None of the subject components are small-bore Class 1 piping components. LRA Table 3.4.2-3 lists Feedwater System Valves (Control, Check, and Hand Valves) (Body and Bonnet) made of stainless steel in treated water (includes steam)(internal), subject to cracking due to SCC and loss of material due to crevice and pitting corrosion, which includes small instrument piping and valves associated with Feedwater System instruments such as level transmitters, pressure differential transmitters and pressure transmitters. LRA Table 3.4.2-4 lists Piping and Fittings (Steam Drains) in treated water (includes steam)(internal) subject to cracking due to SCC and loss of material due to crevice and pitting corrosion, which includes non-safety related orifices.

NRC RAI 3.4-4 In LRA Table 3.4.2-5, titanium condensate coolers/condensers (tubes) in raw water environments are not identified with any aging effects. The same components in treated water (includes steam)(external) environments are subject to loss of material due to crevice corrosion. Provide the basis for determining that no aging effects need to be identified for the titanium condensate coolers/condensers (tubes) in raw water environments.

RAI 3.4-4 Response BSEP developed a set of analytical tools for assessing potential aging effects pertaining to components within the scope of License Renewal. The BSEP Mechanical Tools are based on industry guidance, i.e. Electric Power Research Institute (EPRI) Document TR-1003056, "Non-Class 1 Mechanical Implementation Guideline and Mechanical Tools, Revision 3."

For LRA Table 3.4.2-5, Main Condenser, the titanium condensate coolers/condensers (tubes) shown in a Treated Water environment are normally at a temperature greater than 160'F. The titanium condensate coolers/condensers (i.e., tubes) in a Raw Water environment are normally at a temperature less than 160'F.

Based upon the referenced EPRI document (i.e., Appendix A and B, Table 4-1), the BSEP Mechanical Tools identified that titanium in a Raw Water environment at a temperature less than 160'F does not exhibit aging effects, while titanium in Treated Water environment at a temperature of greater than 160'F was potentially subject to aging effects.

NRC RAI 3.5-1 Refueling bellows (LRA Table 3.5.2-1) are manufactured from stainless steel, and they are protected from weather. The components protected from weather are not necessarily immune to loss of material. As the bellows are located between the refueling cavity and the drywell, they come in direct contact with water, and are subjected to sustained moist condition. In similar situations, the stainless steel bellows of some ice-condenser and Mark 1 containment (see

BSEP 05-0050 Page 60 of 87 IN 92-20) have experienced degradation and cracking. The applicant is requested to provide justification for not managing the aging of the bellows during the period of extended operation.

RAI 3.5-1 Response The refueling bellows is not a containment pressure boundary component and is not subject to the frequency and severity of loading as would be experienced by containment pressure boundary penetration bellows described within NRC IN 92-20, "Inadequate Local Leak Rate Testing." The refueling bellows provides an expansion boundary between the exterior drywell wall and the Reactor Building, inside the refueling cavity. The primary environment seen by the refueling bellows is warm, dry air, with short periods of immersion in demineralized water when the reactor refueling cavity is flooded. Following refueling any residual demineralized water would evaporate quickly. The long term environment, for material aging purposes, is protected from weather, with Reactor Building air on both sides of the bellows. Based on the subject environment and consistent with industry guidance, stainless steel is not subject to degradation.

NRC RAI 3.5-2 Cable trays and conduits (LRA Table 3.5.2-1) are either made of galvanized carbon steel, or stainless steel. The staff agrees that the potential for corrosion of stainless steel cable trays/

conduits is remote, unless they are subjected to sustained high temperatures (> 140'F) and the material yield strength is high (> 140 ksi). Loss of material due to galvanic corrosion is more likely for the cable trays/conduits if they are subjected to humid environment and welded to non-galvanized carbon steel supports. The applicant is requested to discuss why the BSEP cable trays and conduits and all components/commodities included within Notes 521 and 529, do not need aging management. As part of the justification, the applicant is requested to provide operating experience related to these components/commodities.

RAI 3.5-2 Response Only the upper elevations of the drywell are subject to temperatures between 140 and 2000F, and no degradation of galvanized or stainless steel components have been identified within plant operating experience in this area.

Based on industry guidance, loss of material by general corrosion is not an applicable aging effect for galvanized steel exposed to, or protected from weather, unless the pH of precipitation is outside the range of 6 to 12 or temperatures are between 140 and 200'F. Also, based on industry guidance, galvanized steel is not subject to galvanic corrosion because the zinc coating provides galvanic protection of the carbon steel base metal even under degraded conditions.

Therefore, loss of material by galvanic corrosion is not an applicable aging effect for galvanized steel protected from or exposed to weather.

Precipitation is not monitored at BSEP; however, groundwater is monitored for pH and the results show the pH is not outside the range of 6 to 12. Plant operating experience has not identified degradation of galvanized or stainless steel components where the ambient

BSEP 05-0050 Page 61 of 87 environment is not aggressive, which is consistent with the industry guidance discussed above.

Based on review of typical cable tray and conduit support details and discussions with system and welding engineers, BSEP does not weld cable trays or conduits to non-galvanized carbon steel supports. Cable tray and conduit supports are typically fabricated from galvanized unistrut members and fittings. BSEP has identified loss of material as an applicable aging effect for cable trays and conduits and all galvanized and stainless in-scope civil components in the SW Intake Structure, based on the aggressive environment in that location and plant operating experience. See LRA plant-specific Note 544 for further information.

NRC RAI 3.5-3 In the context of NUREG-1801 item II.b2.2.21-g, related to the concrete components subjected to elevated temperatures, the applicant provided an evaluation in Note 536 and in Section 3.5.2.2.1.3. The staff does not agree with the applicant's interpretation that the upper portion of the drywell subjected to sustained temperatures of approximately 170'F can be considered as "local area." However, the staff has, on a case by case, approved such temperatures without complex analysis, provided the concrete components and the load bearing items attached to such concrete components are periodically monitored. In light of the above discussion, the applicant is requested to justify why the items included in Table 3.5.2-1 and covered by Notes 536 and 513 should not be subjected to aging management during the period of extended operation.

RAI 3.5-3 Response Note 536 is applicable to the containment pressure boundary concrete, and Note 513 is applicable to containment internal concrete and concrete outside the containment. The only BSEP concrete above the 150'F temperature level is associated with the upper elevations of the containment pressure boundary concrete as stated in Note 536. The containment pressure boundary concrete is subject to aging management by both the ASME Section XI, Subsection IWL Program and the Structures Monitoring Program; as such, the concrete components are periodically monitored.

NRC RAI 3.5-4 Based on the evaluation provided in Section 3.5.2.2.1.3, a number of load resisting reinforced concrete structures within the drywell shell are likely to be subjected to temperatures higher than the established threshold of 150'F. The applicant is requested to provide the following information related to these structures:

1. Are these structures kept within the threshold temperature 150'F by a cooling system? If yes, please provide a summary of the operating experience related to the reliability of the cooling ventilation system. If no, provide the method of monitoring the temperatures of these structures.

BSEP 05-0050 Page 62 of 87

2. Provide a summary of the results from the latest inspections performed on (1) RPV pedestal supports, (2) the foundation and floor slabs, and (3) the sacrificial shield wall under the existing Structural Monitoring Program.

RAI 3.5-4 Response

1. The containment bulk average temperature is managed under Technical Specification 3.6.1.4, which requires the plant enter Limiting Condition for Operation (LCO) actions if the drywell temperature exceeds 150'F.

2. The last two inspections performed under the existing Structures Monitoring Program, dated March 15, 2004, for Unit 1 and February 25, 2001, for Unit 2, identified no degradation associated with the RPV pedestal supports, the floor slabs, or the sacrificial shield wall, the only issues identified were coating deficiencies, which were referred to the coating inspection program, and an improperly supported grating.

NRC RAI 3.5-5 Item hot penetration insulation, in Table 3.5.2-1, has been screened out as having no aging effects, and it does not require aging management (Note 540). As the inside sustained temperature of the containment is high (> 140'F), and the outside is subjected to the reactor building temperature, the concrete temperatures around these penetration is likely to be high.

The applicant is requested to discuss the plant specific operating experience related to the effectiveness of the insulation in keeping the temperatures around these penetrations (in the containment concrete) below 200'F.

RAI 3.5-5 Response Hot penetration temperatures, recorded on chart paper, were reviewed back to 1997. No penetration temperatures exceeded 200'F, with the highest recorded temperature of 1 850F occurring between June 2003, and August 2003, on one of the main steam lines. As such, the insulation has been proven effective in maintaining hot penetration temperatures below 200'F.

NRC RAI 3.5-6 The staff agrees with the applicant that in general, the sump stainless steel liner is not subjected to aging management, so far as it meets the threshold criteria for stainless steel discussed in RAI 3.5-2. However, the thin sump liner needs to have some type of periodic inspection to assure that it has not bulged excessively between anchors, and not affected by the dissimilar weld details at penetrations and at the junctions of carbon steel components. The applicant is requested to discuss the plant specific as well as the industry experience related to the condition of the stainless steel sump liners, to justify the AMR conclusion that no aging management is needed for stainless steel sump liners.

BSEP 05-0050 Page 63 of 87 RAI 3.5-6 Response The subject sump is fabricated entirely of stainless steel, all attached piping is fabricated from stainless steel, and it does not contain any dissimilar welds. The sump is a very high radiation environment; as such, it is treated as an inaccessible area. The sump pump was modified in 2000 by replacing the submersible pump with a top mount motor and cantilevered pump. No degradation was recorded during installation; however, the water level within the sump was maintained as high as possible for shielding purposes. Any observable degradation identified during periodic maintenance of the pumps, performed every refueling outage, will be evaluated through the normal work process. Although the liner is considered inaccessible, any degradation identified for similar stainless steel liners would be considered applicable to the sump liner and an evaluation performed in accordance with the BSEP corrective action process.

NRC RAI 3.5-7 The staff finds confusing the apparent contradiction in the discussion in item no. 3.5.1-02 and in component 'penetrations" in Table 3.5.2-1 related to aging management of penetrations (including sleeves and bellows). In item 3.5.1-02, the applicant credits the ASME XI, IWE, and 10 CFR 50, Appendix J programs for aging management, and provides acceptable further evaluation in Section 3.5.2.2.1.7. However, in Table 3.5.2-1, the applicant asserts "no aging effects,' and uno AMP." Note 542 reiterates the AMPs stated in item 3.5.1-02. The applicant is requested to clarify the contradictory LRA requirements.

RAI 3.5-7 Response The further evaluation information in Section 3.5.2.2.1.7 addresses cracking in both 3.5.1-02 and 3.5.1-17 components. 3.5.1-02 covers penetration sleeves, bellows, and dissimilar metal welds.

3.5.1-17 addresses steel elements; vent line bellows, vent headers, and downcomers. Therefore, Section 3.5.2.2.1.7 is written to address all of the above components.

With respect to the penetration components (i.e., 3.5.1-02), the aging management review determined that they had no aging effects involving cracking. For those line items on Table 3.5.2-1, generic Note I was used, and a NUREG-1801, Volume 2, line item was referenced to indicate what specific aging effect was not applicable. The aging management programs of ASME Section XI, Subsection IWE and 10 CFR 50 Appendix J are credited for steel components that form the pressure boundary of primary containment. Hence, plant-specific Note 541 was used.

NRC RAI 3.5-8 On the subject of lubrite bearings, the staff has been skeptical about the industry position that no aging management is needed, without providing acceptable technical justification. Some of the aging effects/mechanism could be loss of mechanical function because of distortion, dirt accumulation, fatigue due to vibratory and cyclic thermal loads, and gradual degradation of the

BSEP 05-0050 Page 64 of 87 lubricant used, particularly, when subjected to sustained elevated temperatures, and radiation (inside containment). Without systematic investigation of these factors, it would be difficult to accept a position that "no aging management of lubrite bearings is needed (Note 524). In context of the above discussion, the applicant is requested to provide information to justify that none of the conditions cited in the aging effects/mechanism above is possible where the lubrite plates are used in BSNP.

RAI 3.5-8 Response As addressed by previous applicants, Lubrite resists deformation, has a low coefficient of friction, resists softening at elevated temperatures, absorbs grit and abrasive particles, is not susceptible to corrosion, tolerates high intensities of radiation, and will not score or mar. In addition, Lubrite products are solid, permanent, completely self-lubricating, and require no maintenance. As documented in NUREG-1759, "Safety Evaluation Report Related to the License Renewal of Turkey Point Nuclear Plant, Units 3 and 4," the NRC staff has agreed that there are no known aging effects for Lubrite. A search of industry operating experience found no reported instances of Lubrite plates degrading or failing to perform their intended function; and, after more than 20 years of service, there has been no adverse experience data recorded for BSEP Lubrite plates. Lubrite plates at BSEP are typically located in a closed, clean environment, such as the Drywell or Reactor Building, and are not subject to accumulation of dirt or debris. It is therefore concluded that BSEP Lubrite plates will not require aging management to perform their intended functions for the period of extended operation.

NRC RAI 3.5-9 In the LRA, the applicant did not specify the aging effect requiring management nor aging management program for the embedded/encased carbon steel (Tables 3.5.2.4 and 3.5.2.7) and galvanized carbon steel (Table 3.5.2.4) anchorages/embedment. In Notes Nos. 518 and 519 of LRA Table 3.5.2.4, the applicant stated that the BSEP AMR methodology concluded that carbon/low alloy steel and galvanized carbon/low alloy steel, completely encased in concrete, are not subject to aging effect. The staff's concern is that the carbon/low alloy steel and galvanized carbon/low alloy steel are likely subject to corrosion and loss of material for conditions involving cracked concrete. The applicant is requested to provide its justification for not considering aging effect on these structural elements in light of the staff's concern.

RAI 3.5-9 Response The AMR results reflected in plant-specific Notes 518 and 519 involve components that are completely encased in concrete so that the protection from corrosion afforded by the highly alkaline concrete environment is present.

As specified in NUREG-1557, "Summary of Technical Information and Agreements from Nuclear Management and Resources Council Industry Reports Addressing License Renewal,"

and referenced in GALL, the attributes of a concrete design for which corrosion of embedded steel is not significant are the same as specified for the BSEP concrete design, specifically the

BSEP 05-0050 Enclosure I Page 65 of 87 concrete design is per American Concrete Institute 318-63 with a low water-to-cement ratio and adequate air entrainment.

The RAI postulates a situation where the concrete is cracked. This postulate renders Notes 518 and 519 not applicable. However, the condition of concrete in BSEP structures in scope of License Renewal is monitored by aging management programs that would detect the presence of cracking in the vicinity of embedded steel components. As noted in LRA Table 3.5.1, the ASME Section XI, IWL and Structures Monitoring Programs inspect in-scope concrete structures for all types of aging effects including cracking.

NRC RAI 3.5-10 In LRA Table 3.5.2.4, the applicant did not specify the aging effect requiring management nor aging management program for the carbon steel piles that were driven in undisturbed soil. In Note No. 522 of LRA Table 3.5.2.4, the applicant stated that based on NUREG-1557, steel piles driven in undisturbed soils have been unaffected by corrosion; and those driven in disturbed soil experience minor to moderate corrosion to a small area of metal. Therefore, no aging effects have been concluded for steel piles. It is the staff's understanding that the conclusion of NUREG-1557 (References 16 and 17 of the LRA) is based on less than 40-year data. There are other documents (References 1 and 2 below) which indicate that significant corrosion of steel piles has been identified, even when piles were driven in undisturbed soil. Based on the information identified by the staff, the applicant is requested to provide additional information to justify the validity of its conclusion.

References

1. Probabilistic Model for Marine Corrosion of Steel for Structural Reliability Assessment, Journal ASCE 2003.

2. Corrosion Control Manual for Rail Rapid Transit, UMTA Report UMTA-DC-0152-83-1, 1983.

RAI 3.5-10 Response EPRI TR-103842, Class I Structures License Renewal Industry Report, Section 4.3.1, states:

Romanoff examined corrosion data from 43 piling installations and on that basis drew some general conclusions regarding the corrosion of driven steel piles. These test installations had pile depths of up to 136 feet and time of exposure varying from 7 to 50 years in a wide variety of soil conditions. Romanoff's review of this data indicates that the type and amount of corrosion observed on steel pilings driven into undisturbed natural soil, regardless of the soil characteristics and properties, is not sufficient to significantly affect the strength of pilings as load bearing structures. The data also indicate that undisturbed soils are so deficient in oxygen at levels a few feet below the

BSEP 05-0050 Page 66 of 87 ground surface or below the water table, that steel piles are not appreciably affected by corrosion, regardless of the soil type or the soil properties.

Foundation pile corrosion is non-significant for the period of extended operation and will not prevent the foundation piles from performing their License Renewal intended functions. This conclusion is consistent with NUREG-1557 and EPRI Report TR-103842.

References I and 2 in the RAI are not readily available for review and, therefore, have not been compared to NUREG-1557 or EPRI Report TR-103842.

NRC RAI 3.5-11 LRA Section 3.5.2.2.2.1, "Aging of Structures Not Covered by Structures Monitoring Program,"

states that aging effects associated with aggressive chemical attack of concrete, etc. are not applicable as discussed in the plant specific notes associated with LRA Tables 3.5.2-1 through 3.5.2.15. In LRA Tables 3.5.2.2 through 3.5.2-15, the applicant, based on the Plant Specific Notes 501 and 517, did not specify the aging effect requiring management for Class I below grade concrete structures (reactor building, augmented off-gas building, diesel generator building, control building, turbine building, radwaste building, and miscellaneous structures and out buildings). Note 501 states that although no aging effects have been identified, the specified NUREG-1801 program will be assigned for management of this commodity, in accordance with the NRC's current position (ISG-03), and Note 517 states that groundwater monitoring is performed periodically to validate the assumption that the groundwater below-grade environment is not aggressive. In LRA Section 3.5.2.2.2.2, 'Aging Management of Inaccessible Areas," the applicant stated that the service water intake structure is the only structure with concrete elements subject to aggressive groundwater. The structure is located adjacent to the intake canal; therefore, the environmental parameters of intake water have been applied to the below grade portions of the concrete. However, no aging effect requiring management nor aging management program are identified for the service water intake structure in Table 3.5.2-7. The applicant is requested to provide its basis for not to specify aging effect requiring management and aging management program for the service water intake structure. The applicant is also requested to provide information to explain how the water chemistry is monitored including the past and current groundwater qualities (pH values and content of chlorides and sulfates),

frequency of monitoring, specific monitoring program used, and future plan for groundwater monitoring.

RAI 3.5-11 Response The aging effect associated with an aggressive environment is credited in Table 3.5.2-7 and the Structures Monitoring Program was specified for its management. BSEP commodity groups "Concrete above grade" and Concrete below grade" are sub-divided by associated GALL items.

GALL items III.A6.1-d and III.A6.1-e, whose environment is "Exposure to aggressive environment," are identified in Table 3.5.2-7 as having an aging effect requiring management.

BSEP 05-0050 Page 67 of 87 Aging effects associated with freeze/thaw (i.e., llI.A6.1-a) and reaction with aggregates (i.e.,

III.A6.1-c) were excluded based on GALL criteria as discussed in Notes 504 and 505; however, the Structures Monitoring Program was credited for management based on ISG-03.

The aging effect associated with erosion of porous concrete subfoundation (i.e., III.A6.1-g) was determined to be not applicable to BSEP, as discussed in Note 507.

The aging effect associated with settlement (i.e., III.A6.1-f) was determined to be not applicable to BSEP, as discussed in Note 506.

Periodic groundwater monitoring is currently being performed under Section 10.7 of implementing procedure OE&RC-3250, "Groundwater Monitoring Program," and will be continued during the period of extended operation. An enhancement to the Structures Monitoring Program implementing procedure EGR-NGGC-0351, "Condition Monitoring of Structures," will be performed prior to the period of extended operation that requires the Structures System Engineer to review the groundwater monitoring results against the applicable parameters for determination of an aggressive below grade environment.

Groundwater monitoring for pH, chlorides, and sulfates has been performed twice since 2002.

The groundwater monitoring for phosphates was performed once and is not part of the groundwater monitoring program. The following table provides the results against the criteria in GALL, which shows the values to be below the aggressive limits.

GALL Well #

Well #

Well #

Well #

Manhole ParameCriteria ESS-1B ESS-2B ESS-3B ESS-13C 2-MH-CB7 Date Date Date Date Date 2002 2004 2002 2004 2002 2004 2002 2004 2002 2004 pH<5.5

7.

04 6.57 1 6.88 6.96 7.16 6.61 6.69 N/A 6.39 Chlorides

> 500 ppm 36 26 4

31 27 12 34 21 N/A 11 Sulfates

> 1500 ppm 2

5 66 148 50 10 18

<5 N/A 45 A one-time inspection was performed on well number ESS-3B to determine a groundwater phosphate level; that value was found to be 0.12 ppm.

NRC RAI 4.2-1 Section 4.2 of the Carolina Power and Light Company (CP&L) license renewal application (LRA) for Brunswick Steam Electric Plant, Units 1 and 2 (BSEP-1/2 for Units 1 and 2, BSEP-1 for Unit 1, and BSEP-2 for Unit 2) identifies that loss of fracture toughness/neutron irradiation embrittlement assessments for the ferritic reactor vessel (RV) beltline base-metal and weld components are time-limited aging analyses (TLAAs) for the BSEP-1/2 license renewal application (LRA). LRA Table 4.2-5 for the BSEP-l RV components and LRA Table 4.2-6 for BSEP-2 RV components include loss of fracture toughness/neutron irradiation embrittlement TLAA calculations for the N-16 A and B Instrumentation Nozzle Forgings. Confirm whether BSEP-1/2 has performed 54 EFPY TLAA assessments on upper shelf energy (USE) calculations and 1/4T RTNDT calculations for the nozzle shell welds that were used to fabricate the N-16 A

BSEP 05-0050 Page 68 of 87 and B instrumentation nozzles and, if so, whether the applicable TLAA calculations for the N-16 A and B nozzle shell welds have been included in Section 4.2 of the LRA. If CP&L does have applicable 54 EFPY TLAA data and calculations for these welds, but has not included them in the BSEP-1/2 LRA, please update Section 4.2 of the LRA to include the applicable TLAA assessments for the N-16 A and B nozzle shell welds.

RAI 4.2-1 Response The N-16 nozzle shell welds are bounded by the limiting beltline welds identified in Table 4.2-5 for Unit 1 and Table 4.2-6 for Unit 2. Therefore, no separate 54 Effective Full Power Years (EFPY) TLAA assessment is required for these welds. No update is required for Section 4.2 of the LRA.

NRC RAI 4.2-2 10 CFR 54.3 provides that staffs criterion for determining whether a given plant analysis is within the scope of the definition for aTLAA. Section 5.3.3.1.3 of the BSEP-1/2 UFSAR indicates that a 40-year RV thermal shock analysis was performed on a BWR RV that is representative of the RVs at BSEP-1/2. The UFSAR section also stated that the GE analysis indicated that a single recirculation line break event could be tolerated at the end of the 40-year design life because the effects of neutron irradiation or other normal service fatigue damage are not expected to appreciably affect the single event tolerable strains. Based on the discussion in BSEP UFSAR Section 5.3.3.1.3, the staff concludes that the RV reflood thermal shock may meet the definition of a TLAA, as defined in 10 CFR 54.3. In contrast, CP&L has not identified that RV reflood thermal shock safety analysis is a TLAA for the BSEP-1/2 LRA. Provide your technical/regulatory basis for making this determination. If the BSEP RV thermal shock analysis is determined to meet the definition in 10 CFR 54.3 for TLAAs, amend the BSEP-1/2 LRA to include the RV thermal shock TLAA for BSEP-1/2, including an appropriate FSAR Supplement summary description for the analysis, as is required by 10 CFR 54.21(d).

RAI 4.2-2 Response The Reactor Vessel thermal shock analysis described in UFSAR 5.3.3.1.3 has been determined to meet the definition of 10 CFR 54.3 for TLAAs. The evaluation of this TLAA is shown in the following paragraphs.

Summary Description Section 5.3.3.1.3 of the USFAR includes an end-of-life (i.e., 40-year) thermal shock analysis performed for the reactor vessel for a design basis LOCA followed by a low-pressure coolant injection. The reflood shock refers to the stress imposed upon the reactor vessel due to contact between the hot vessel shell and the cold water injected to reflood the vessel. The UFSAR states:

BSEP 05-0050 Enclosure I Page 69 of 87 A detailed reactor vessel thermal shock analysis was performed on a representative GE BWR reactor vessel. The thermal shock analysis simulating ECCS-LOCA operation was performed on a reactor vessel design similar to the vessel for this facility and was reported in a GE Topical Report submitted to the AEC in July 1969.

This General Electric (GE) report indicated that a single recirculation line break event could be tolerated at the end of the 40-year design life because the effect of neutron irradiation or other normal service fatigue damage is not expected to appreciably affect the single event tolerable strains.

Since the material properties were based upon 40-year fluence values, they meet the requirements of 10 CFR 54.3(a). As such, the analysis based upon these properties is a TLAA.

Analysis For the current operating period, a thermal shock analysis was originally performed on the reactor vessel components for a standard design. The analysis assumed a design basis LOCA followed by a low-pressure coolant injection accounting for the full effects of neutron embrittlement at the end-of-life (i.e., 40 years). The analysis showed that the total maximum vessel irradiation at the mid-core inside of the vessel to be 2.4E+17 n/cm2, which was below the threshold level of any nil-ductility temperature shift for the vessel material. As a result, it was concluded that the irradiation effects on all locations of the reactor vessels could be ignored.

However, this analysis only bounded 40 years of operation.

Disposition: Revision, 10 CFR 54.21(c)(1)(ii)

The original analysis has since been superseded by a 40-year analysis for BWR/6 reactor vessels:

"Fracture Mechanics Evaluation of a Boiling Water Reactor Vessel Following a Postulated Loss of Coolant Accident," Ranganath, S., Fifth International Conference on Structural Mechanics in Reactor Technology, Berlin, Germany, August 1979, Paper G1u5. The reactor vessels at BSEP are BWRI4. The BWR/6 evaluation determined the maximum stress intensity in the vessel wall as a function of vessel wall thickness and time after the Design Break LOCA. As shown in Figure G2214-1 of ASME Section XI, Appendix G; 1998 Edition through 2000 Addenda, the stress intensity is a function of vessel wall thickness. The original analysis used a recirculation line break, while the BWR/6 analysis was based on a main steam line break event, which is considered to bound the recirculation line break. In addition, the BWR/6 analysis used a vessel thickness similar to that of the BSEP vessels.

Therefore, the BWR/6 analysis is considered applicable to the BSEP reactor vessels, and is considered to be a revised analysis for License Renewal. This BWR/6 analysis assumes 40-year, end-of-life material toughness, which in turn depends on end-of-life-adjusted reference temperature (ART). The critical location for the fracture mechanics analysis is at l/4 of the vessel thickness (i.e., from the inside, 1hT). For this event, the peak stress intensity occurs at approximately 300 seconds after the LOCA. The analysis shows that at 300 seconds into the thermal shock event, the temperature of the vessel wall at 1.5 inches deep, which is 14T, is approximately 400'F.

BSEP 05-0050 Page 70 of 87 The worst-case calculated ART resulting from 54 EFPY radiation exposure (i.e., 60 years) was determined to be 136.10F, which is well below the 400'F 1/4/4T temperature predicted for the thermal shock event at the time of peak stress intensity. Therefore, the BSEP reactor vessels are qualified through the end of the period of extended operation.

This TLAA has been projected to the end of the period of extended operation, using Method (ii) of 10 CFR 54.21(c)(1).

NRC RAI 4.2.4-1 Section A.1.2.1.3 of the BSEP-1/2 LRA provides CP&L's FSAR Supplement summary description for the TLAA on pressure-temperature (P-T) limits. The summary description provides a sufficient basis for concluding that the P-T limits for BSEP-1/2 are a TLAA for the facilities and for stating why the applicant has developed P-T limit curves for the periods of extended operation. However, in accordance with this license amendment process, the P-T limit curves for the BSEP-1/2 extended periods of operation will require NRC review and approval prior to the expiration of the 32 EFPY P-T limit curves that are currently approved in the BSEP-1/2 Technical Specifications. The staff requests that the FSAR Supplement summary description be amended to state: (1) that the P-T limit curves for the BSEP-1/2 periods of extended operation will be submitted for NRC review and approval in accordance with the 10 CFR 50.90 license amendment process at least one year prior to expiration of the 32 EFPY P-T limit curves that are currently approved in the BSEP-1/2 Technical Specifications, and (2) as mandated in 10 CFR Part 50, Appendix G. this is required to cover P-T limit curves for the extended operating periods during both normal operations of the reactor (including heatups and cooldowns of the reactor, critical operations of the reactor, and transient operating conditions) and RV pressure test conditions.

RAI 4.2.4-1 Response P-T limit curves for the BSEP Units 1 and 2 periods of extended operation will be submitted for NRC review and approval in accordance with the 10 CFR 50.90 license amendment process at least one year prior to expiration of the 32 EFPY P-T limit curves that are currently approved in the BSEP Technical Specifications. As mandated in 10 CFR Part 50, Appendix G. this is required to cover P-T limit curves for the extended operating periods during both normal operations of the reactor, including heatups and cooldowns of the reactor, critical operations of the reactor, and transient operating conditions, and RV pressure test conditions. LRA Appendix A, Section A. 1.2.1.3 will be revised to include this commitment.

NRC RAI 4.2.5-1 On July 28, 1998, the NRC staff issued a Safety Evaluation Report (SER) of BWRVIP-05. In this SER, the staff concluded that the failure frequency of reactor vessel (RV) circumferential welds in boiling water reactors (BWRs) was sufficiently low to justify elimination of inservice

BSEP 05-0050 Page 71 of 87 inspection (ISI) of these welds. However, the staff also indicated that examination of the circumferential welds would need to be performed if the corresponding volumetric examinations of the RV axial welds revealed the presence of an age-related degradation mechanism. Confirm whether or not CP&L's past volumetric examinations of the BSEP-1/2 RV axial welds have indicated the presence of cracking or other age-related degradation mechanisms in the welds.

RAT 4.2.5-1 Response No cracking or age-related degradation mechanisms have been identified during volumetric examinations of the RV axial welds during inservice inspections to date.

NRC RAI 4.2.5-2 In CP&L's response to Generic Letter 92-01, Revision 1, Supplement 1, dated November 16, 1995, CP&L established 100F as the official initial (unirradiated) RTNDT value for the FG circumferential welds (i.e., the weld from Heat No. IP4218 for BSEP-1 and the weld from Heat No. 3P4000 for BSEP-2), as based on the NRC Branch Position MTEB 5-2. However, in Table 4.2-7 of BSEP-1/2 LRA, CP&L listed -50'F as the initial RTNDT value for the FG circumferential welds, as based on the NRC-approved methodology in General Electric (GE)

Topical Report No. NEDC-32399-P (refer to NRC safety evaluation [SE] dated December 16, 1994). In its letter and SE to the Boiling Water Reactor Owners Group (BWROG), the staff informed the BWROG that use of the methodology in Topical Report No. NEDC-32399-P is limited to nuclear plants that meet the following criterion:

The staff concludes that the GE RTNDT estimation method is an acceptable alternative for determining initial RTNwr values for vessel beltline materials lacking complete material test data. In future applications, licensees should still use the procedure in the ASME Code for determining initial RTNDT values. This method should only be applied to interpret incomplete old test data obtained prior to the summer of 1972.

The staff has the following requests in regard to how the set of initial Charpy-impact/drop weight test data for the FG circumferential welds conforms to this criterion, such that the GE methodology could be applied to re-establish the initial RTNDT value for these welds:

A.

Clarify whether on not the set of initial Charpy-impact/drop weight test data for the FG circumferential welds conforms to the stated criterion on use of the GE methodology.

B.

Explain the use of the technical data (including any and all applicable Charpy-impact, drop weight test data and curves) in applying the GE methodology to establish the initial RTNDT value as -50F. If the new initial RTNDT value for the RV FG circumferential welds is based on a set of generic drop weight/Charpy-impact data, provide the standard deviation on the set of data used to establish the new mean initial RTNDT value (i.e.,

provide the c1 value, as defined in Position 1.1 of RG 1.99, Revision 2).

BSEP 05-0050 Page 72 of 87 RAI 4.2.5-2 Response A.

The GE method should only be applied to interpret incomplete old test data obtained prior to the summer of 1972. The BSEP reactor vessels were ordered prior to 1972 and the issuance of Appendix G to 10 CFR 50.

The initial set of BSEP test data for the FG circumferential welds only include three Charpy V-notch tests at +100F. No drop weight tests were performed.

This conforms to the stated criterion on use of the GE methodology.

B.

The test data at +10 0F for the two welds are as follows:

Heat Number IP4218 Heat Number 3P4000 94, 91, and 90 ft-lbs 97, 95, and 88 ft-lbs The test data are contained in Appendix C to GE Report NEDO-24161, for Unit 1, and NEDO-24157, for Unit 2. These reports were provided to the NRC as enclosures to a BSEP letter from R.P. Lopriore to the NRC, (Serial: BSEP 94-0316), "Submittal of Reactor Vessel Material Surveillance Specimen Test Results for Brunswick Unit 1," dated August 17, 1994.

10 CFR 50 Appendix G states that for vessels constructed to a version of the ASME Code prior to Summer 1972 Addendum, fracture toughness data and data analyses must be supplemented in an approved manner.

The Charpy results are used to establish the initial RTNDT. First, T50 is established. T5o is the temperature at which the Charpy V-notch 50 ft-lb energy and 35 mils lateral expansion are met. Then, the initial Reference Temperature for Nil-Ductility Transition (RTNDT) can be calculated from the following equation:

Initial RTNDT = T5o - 60'F In the absence of a Nil-Ductility Transition Temperature (NDTT) value (i.e., based upon drop weight tests), the GE Methodology requires that the value of initial RTNDT be -50 0F or greater.

For the two BSEP welds in question, the minimum Charpy V-notch value is greater than 50 ft-lbs, therefore, T50 = 100F.

The initial RTNDT is then calculated as follows:

Initial RTNDT = Ts0 - 600F = 100F - 60'F = -500F Tables 4.2-5 and 4.2-6 of the BSEP LRA show the value of al is set to 00F.

BSEP 05-0050 Page 73 of 87 NRC RAI 4.2.6-1 In the staff's supplemental safety evaluation report (SER) on Topical Report BWRVIP-05, dated March 7, 2000, the staff approved four Case Studies for evaluating the probability of failure analyses for beitline axial welds in boiling water reactor (BWR) reactor vessels (RVs). These Case Studies include the Clinton Nuclear Plant Case Study and three variations of the Pilgrim Nuclear Plant Case Study. These Case Studies are provided in Table 1 for reference:

Table 1: Comparison of Results from Staff and BWRVIP Initial Vessel Failure Freq.

RTNDT Mean Plant (OF)

RTNUr (°F)

Staff BWRVIP Clinton

-30 91 2.73 E -6 1.52 E -6 Pilgrim

-48 68 2.24 E -7 Mod I 0

116 5.51 E -6 1.55 E -6 Mod2**

-2 114 5.02 E -6 A variant of Pilgrim input data, with initial RTNDT = 0 OF

• • A variant of Pilgrim input data, with initial RTNDT = -2 0F In regard to the background information for these Case Studies, the Pilgrim RV was fabricated by the Combustion Engineering Corporation (CE) and the Clinton RV was fabricated by Chicago Bridge and Iron Works (CB&I). In the BSEP-1/2 LRA, CP&L has opted to use the "Mod 2" variant of the Pilgrim Case Study as the acceptance criterion basis for evaluating the TLAA on the RV axial weld probability of failure analyses. The BSEP-1/2 RVs were fabricated by CB&I.

Therefore, it appears to the staff that the Clinton Case Study may be the more appropriate Case Study for evaluating the beltline axial welds in the BSEP-1/2 RVs. Justify your basis for using the "Mod 2" variant of the Pilgrim Case Study as the basis for evaluating this TLAA on the RV axial weld probability of failure analyses in lieu of using the Clinton Case Study.

RAI 4.2.6-1 Response The NRC Supplemental SER on Topical Report BWRVIP-05, dated March 7, 2000, concluded:

The results of these calculations indicate that the RPV failure frequency due to failure of the limiting axial welds in the BWR fleet are below 5 x 10-6 per reactor-year, given the assumptions on flaw density, distribution and location described previously.

The "Mod 2" variant of the Pilgrim Case Study, with a failure frequency of 5.02 x 10-6 per reactor-year, was chosen because it most closely aligns with the conclusion of the safety evaluation report.

BSEP 05-0050 Page 74 of 87 A review of Table 4.2-8 of the BSEP LRA shows that the Mean ART of 530F is less than the Mean ART in any of the four cases shown in the supplement to the safety evaluation for BWRVIP-05, including the Clinton Case Study.

Therefore, the conclusions of the TLAA evaluation remain valid.

NRC RAI 4.2.7-1 Section 4.2.7 of the BSEP-1/2 LRA provides CP&L's TLAA for the RV core shroud reflood thermal shock analysis. In this section of the LRA, CP&L identified that the 40-year core shroud strain analysis during a post-LOCA low pressure coolant injection (LPCI) reflood of the core shroud was a TLAA for BSEP-1/2, as defined in 10 CFR 54.3. The applicant identified that the impact of the neutron fluence on the strain analysis was one of bases that required the analysis to be within the scope of the definition for TLAAs, as defined in 10 CFR 54.3. In reviewing the information in LRA Section 4.2.7 and in BSEP UFSAR Section 3.9.2.5, the staff could not determine what acceptance criterion was being used for the maximum amount of allowable strain that could be tolerated in the core shroud during a post-LOCA LPCI reflooding event, or what neutron fluence was used to establish the maximum allowable strain criteria for core shroud welds and plates. Provide responses to the following Requests for Additional Information on this TLAA:

A.

Clarify what %-elongation strain acceptance criteria are being used for the core shroud welds and plates in the TLAA assessment and what maximum limit is being established in neutron fluence level (i.e., in n/cm2, E 2 1.0 MeV) to be consistent with the

%-elongation strain acceptance criteria used for the TLAA assessment. Clarify what actions would need to be taken by CP&L if the maximum limit on neutron fluence level for the core shroud is exceeded (e.g., refinement of the core shroud reflood thermal shock analysis, etc.).

B.

It has been stated that the maximum tolerable amount of strain in the Type 304 stainless steel plates has been measured to be 20 %-elongation at a temperature of 290'C (554 0F) and a neutron fluence of 8._X1021 n/cm2 (E 2 1.0 MeV) and that the maximum amount of strain in Type 304 stainless steel weld metal has been measure to be 4 %-elongation at a temperature of 2970C (567°F) and a neutron fluence level of 8.OX1021 n/cm2 (E 2 1.0 MeV). Confirm whether Topical Report BWRVIP-35 provides the technical bases for these measured strain criteria, and if so, whether the topical report has been reviewed and approved by the NRC. If BWRVIP-35 does not provide the basis for these measured strain criteria, identify which technical report or analysis does provide the technical basis for these measured strain criteria.

RAI 4.2.7-1 Response A.

BWRVIP-35, "Fracture Toughness and Tensile Properties of Irradiated Austenitic Stainless Steel Components Removed from Service," EPRI TR-108279, dated June 1997,

BSEP 05-0050 Page 75 of 87 provides data on fracture toughness and tensile properties of austenitic stainless steel in-core components removed from service in an operating nuclear power plant. These samples include weld materials and plate materials. Both the plate and weld materials were exposed to neutron fluence of 8.OE+21 n/cm2 (E>1.0 MeV). Tensile tests were performed for each group of the samples with the following results.

The average percent elongation for weld materials tested at 2900C (i.e., 5540F) was 4 percent. This 4 percent elongation value was used as the acceptance criterion for evaluating core shroud welds in the TLAA assessment.

The average percent elongation for plate materials tested at 2970C (i.e., 5670F) was 20 percent. This 20 percent elongation value was used as the acceptance criterion for evaluating core shroud plate materials in the TLAA assessment.

The 8.OE+21 n/cm2 (E>1.OMeV) neutron fluence value is considered to be the limit for applying these test results. However, this value is not expected to be exceeded within 60 years. The 54 EFPY fluence value at the most irradiated point on the shroud was calculated to be 4.17E+21 n/cm2 (E>1.OMeV), using approved fluence methodology. If it is determined that this fluence value will be exceeded, the core shroud reflood thermal shock analysis will be refined or another suitable evaluation will be developed as necessary.

B.

BWRVIP-35 provides actual results from tensile tests performed on samples taken from in-core components removed from an operating nuclear power plant after long periods of service. The technical basis for using these results is that they are representative of the material properties expected for similar materials under similar operating conditions, including neutron fluence and temperature. BWRVIP-35 has not been reviewed and approved by the NRC.

NRC RAI 4.2.8-1 The staff requests that the following RAIs be addressed on TLAAs for spring-loaded or bolted connections in the BSEP-1/2 core plates.

Part A.

In Section 4.2.8 of the application, the applicant indicated that the analysis for installing the spring-loaded BSEP-2 core plate plugs was a TLAA for the BSEP-1/2 LRA because the amount of stress relaxation in the plugs was, in part, dependent on the accumulated neutron fluence in the plugs. However, CP&L did not reference the specific title and date of the analysis that met the criteria for this TLAA. Reference by title and date which design basis or current licensing basis (CLB) document establishes the stress relaxation analysis for the spring loaded BSEP-2 core plate plugs as a TLAA for the BSEP-1/2 application. Clarify whether the analysis is a generic or plant-specific analysis and whether the analysis has been approved by the

BSEP 05-0050 Page 76 of 87 staff. If the analysis has been approved by the staff, reference the title and date of the staff's safety evaluation on the stress-relaxation analysis.

Part B.

In BWRVIP-25, the BWRVIP established that core plate designs with rim hold down bolts would need to treat stress relaxation of the bolts as a potential TLAA. This was identified as Applicant Action Item No. 3 on BWRVIP-25. To respond to this Action Item (i.e. in Table 3 of AMP No. B.2.28 of the BSEP-1/2 LRA), CP&L stated that "the potential susceptibility of the rim hold down bolts to stress relaxation was evaluated as a potential TLAA, but no TLAA was identified." This is consistent with page 3.1-51 of LRATable 3.1-1, in which CP&L does not identify stress relaxation as an applicable aging effect requiring management for the core plate bolts. The following clarification is necessary for completion of the staff's review:

I. Clarify whether the core plate rim hold down bolts are within the scope of license renewal and require an aging management review (AMR). Confirm whether or not the core plate bolts referred to on page 3.1-51 of LRATable 3.1-1 are the same components as the core plate rim hold down bolts that are referred to on page B-82 of the application.

2. If the core plate rim hold down bolts do require an AMR, justify your basis for concluding that stress relaxation does not require aging management and for concluding that a TLAA is not appropriate for the core plate rim hold down bolts, as is otherwise recommended in BWRVIP-25. If CP&L determines that loss of preload/stress relaxation of the core plate rim hold down bolts is an aging effect requiring management, amend LRA Table 3.1-1 to include an AMR entry on how loss of preload/stress relaxation will be managed in the components during the periods of extended operation for BSEP-1/2. If CP&L determines that a TLAA is necessary to manage loss of preload/stress relaxation in the core plate rim hold down bolts, amend Chapter 4.0 of the BSEP-1/2 LRA to include a TLAA on loss of preload/stress relaxation of the core plate rim hold down bolts.

RAI 4.2.8-1 Response Part A.

A plant-specific analysis was performed for the purpose of extending the life of the core plate plugs beyond GE's revised service life. This analysis has not been approved by the NRC staff. This plant-specific analysis was conservatively considered to be a TLAA. As stated on page 4.2-13 of the LRA:

The projected relaxation is based upon 40-year fluence values, although it was only shown to be valid for up to 24 EFPY.

Since the 24 EFPY is less than the currently projected 32 EFPY at 40 years, BSEP chose to manage these components by replacing them at the end of their qualified life by using AMP B.2.28, Reactor Vessel and Internals Structural Integrity Program, described on page B-74 of the LRA.

BSEP 05-0050 Page 77 of 87 Part B.

1. The core plate rim hold down bolts are within the scope of License Renewal and require an AMR. However, the AMR for core plate bolts appears on page 3.1-48 of LRA Table 3.1-1. They are referred to as "Core Shroud and Core Plate (Core Plate Bolts)." These are the same components as the core plate rim hold down bolts that are referred to on page B-82 of the application.

2. BSEP has performed a plant-specific evaluation and determined that a minimum of forty-eight core plate rim hold-down bolts are required for BSEP in order to resist seismic shear loads and maintain minimum safety margins. This quantity of bolts applies for the case of intact but un-preloaded bolts (emphasis added), and is independent of accumulated fluence level.

Since the core plate rim hold down bolts can perform their intended function without the benefit of preload and independent of accumulated fluence, loss of preload due to stress relaxation does not require aging management. This was the basis for the response to Applicant Action Item 4 to BWRVIP-25 which states on page B-82 of the LRA:

Susceptibility of the rim holddown bolts to stress relaxation was evaluated as a potential TLAA, but no TLAA was identified.

NRC RAI 4.2.8-2 Part A.

CP&L's FSAR Supplement summary description on the TLAA for the BSEP-2 spring-loaded core plate plugs discusses CP&L's intent to use the Reactor Vessel and Internals Structural Integrity Program as the basis for managing loss of preload/stress relaxation in the core plate plugs. CP&L has also included this aging management strategy as a commitment in the Commitment Tracking List (CTL) for the application, which was submitted in Enclosure 1 of BSEP Serial Letter No.

BSEP-04-006, dated October 18, 2004. In the CTL entry, CP&L indicated that the commitment for managing loss of preload/stress relaxation in the BSEP-2 spring-loaded core plate plugs has been incorporated into the FSAR supplement summary description for the TLAA (i.e., in Section A.1.2.1.7 of the LRA) and the FSAR supplement summary description for the Reactor Vessel and Internals Structural Integrity Program (i.e., in Section A.1.1.30 of the LRA). However, the staff has determined that the commitment on management of loss of preload/stress relaxation BSEP-2 core plate plugs has not yet been incorporated into the FSAR Supplement summary descriptions for LRA Sections A.1.2.1.7 and A.1.1.30. The staff requests that LRA Sections A.1.2.1.7 and A.1.1.30 both be amended to incorporate this commitment.

BSEP 05-0050 Page 78 of 87 Part B.

The FSAR Supplement Summary description includes the following incomplete sentence: "The loss of preload may cause the plug to leak at a higher rate than the designed." The staff requests that this sentence be fixed editorially.

RAI 4.2.8-2 Response As stated in the response to RAI 4.2.8-1, the core plate plugs will be replaced at the end of their qualified life by using AMP B.2.28, Reactor Vessel and Internals Structural Integrity Program described on page B-74 of the LRA.

Part A.

The scope of the commitment for "Time Limited Aging Analysis (TLAA) - Core Plate Plug Spring Stress Relaxation" specifically states:

Management of Core Plate Plug Spring Stress Relaxation will be performed by means of the Reactor Vessel and Internals Structural Integrity Program.

This line references Sections A.1.2.1.7 and A.1.1.30 of the LRA. Section A.1.2.1.7 of the USFAR Supplement Summary does contain the commitment to manage these components using the Reactor Vessel and Internals Structural Integrity Program as follows:

Therefore, loss of pre-load due to stress relaxation of the core plate plug spring will be managed programmatically by means of the Reactor Vessel and Internals Structural Integrity Program.

Section A.1.1.30 does contain the summary description of the Reactor Vessel and Internals Structural Integrity Program and does not require listing the specific components managed and associated aging effects.

Nuclear Energy Institute (NEI) letter from A. P. Nelson to P. T. Kuo, USNRC, "Industry Response -

Consolidated List of Commitments for License Renewal, December 16, 2002," dated February 26, 2003, stated:

The industry has agreed to identify the high level future commitments in their (U)FSAR supplement (Appendix A of the LRA). Examples of what is meant by 'high level' can be seen in the enclosures.

Therefore, no changes are required.

Part B.

BSEP will correct the UFSAR Supplement Summary description in LRA, Appendix A, Section A.1.2.1.7, to revise the sentence to state:

The loss of preload may cause the plug to leak at a higher rate than designed.

BSEP 05-0050 Page 79 of 87 NRC RAI 4.2.9-1 Part A.

In Section 4.2.9 of the BSEP-1/2 LRA, CP&L identifies that a plant-specific safety assessment was conducted on the BSEP-1/2 core shroud repair designs (i.e., repair clamps) to justify installation of the repair clamps (i.e., bracket assemblies) over the H2 and H3 circumferential welds in the BSEP-1/2 core shrouds. Although the staff is aware that the safety assessment of the repair clamps was submitted to the NRC and approved by the staff, the staff has been unable to track the safety assessment and the staffs safety evaluation on the assessment in the NRC's Agencywide Documents Access and Management System. Identify which plant-specific BSEP evaluation/document contains the safety assessment on the BSEP core shroud repair clamps and which NRC safety evaluation was issued on the plant specific safety assessment for the clamps. Please include Serial Letter Number (if applicable),

Document Title, and the Issuance Date for the reference documents.

Part B.

Confirm that the core shroud repair designs at BSEP-1/2 currently use core shroud repair clamps (bracket assemblies) and that the repair designs have not yet been upgraded to the types of tie-rod assembly designs that have been used in the repair of other U.S. BWR core shrouds.

RAI 4.2.9-1 Response Part A.

The safety evaluation that contained the staff's evaluation of the core shroud repair hardware is contained in the following letter:

Letter from P. D. Milano, Sr. Project Manager, Project Directorate II-1, Division of Reactor Projects - MI11, Office of Nuclear Reactor Regulation, USNRC to R. A. Anderson, Vice President, Carolina Power & Light Company, Brunswick Steam Electric Plant, "Evaluation and Repair of the Core Shroud Cracks, Brunswick Steam Electric Plant, Unit 1 (TAC No. M87270)," dated January 14, 1994.

On August 24, 1994, BSEP submitted its response to Generic Letter 94-03, "Intergranular Stress Corrosion Cracking of Core Shrouds in Boiling Water Reactors."

This response included a description of the installation of a series of clamps encompassing the H2 and H3 welds. These clamps are the core shroud repair hardware. The details of this submittal letter are as follows:

Letter from R. A. Anderson, BSEP to USNRC (Serial: BSEP 94-0335),

"Intergranular Stress Corrosion Cracking of Core Shrouds In Boiling Water Reactors," dated August 24, 1994.

The safety evaluation related to the response to Generic Letter 94-03 was issued on January 3, 1995. The details of the NRC acceptance of the justification for continued operation are contained in the following correspondence:

BSEP 05-0050 Page 80 of 87 Letter from P. D. Milano, Sr. Project Manager, Project Directorate 11-1, Division of Reactor Projects - MI/I, Office of Nuclear Reactor Regulation, USNRC to R. A. Anderson, Vice President, Carolina Power & Light Company, Brunswick Steam Electric Plant, Generic Letter 94-03, "Intergranular Stress Corrosion Cracking of Core Shrouds in Boiling Water Reactors, Brunswick Steam Electric Plant, Units 1 and 2 (TAC Nos. M90084 AND M90085)," dated January 3, 1995.

Part B.

The core shroud repair designs at BSEP Units 1 and 2 currently use core shroud repair clamps (i.e., bracket assemblies) and the repair designs have not been upgraded to the types of tie-rod assembly designs that have been used in the repair of other U.S. BWR core shrouds.

NRC RAI 4.3-1 Table 4.3.2 of the LRA lists reactor vessel components for which 40-year fatigue CUFs were determined in the original stress report. Some components are listed as "exempted." Provide justification why these components were exempted from fatigue analysis.

RAI 4.3-1 Response The reactor vessel was designed in accordance with the 1965 Edition of ASME Section III.

Paragraph N-415 provides the rules for Analysis of Cyclic Operation, which includes the following statements:

If the specified operation of the vessel meets all of the conditions of N-415.1, no analysis for cyclic operation is required, and it may be assumed that the peak stress limit discussed in N-414.5 has been satisfied by compliance with the applicable requirements for materials, design, fabrication, testing, and inspection of this Subsection. If the operation does not meet all the conditions of N-415.1, a fatigue analysis shall be made in accordance with N-415.2 or a fatigue test shall be made in accordance with 1-1080.

Paragraph N-415.1 addresses Vessels Not Requiring Analysis for Cyclic Operation, and subparagraphs a - f provide specific criteria for exempting a component from fatigue analysis.

The cumulative usage factors (CUFs) of components in Table 4.3.2 of the LRA that are listed as exempted were those in the RPV stress report that were reported to have met all of the conditions of N-415.1 and were thus exempted from the fatigue analysis requirements.

NRC RAI 4.3-2 Section 4.3.2 of the LRA states that, except for the RPV shroud support and the RPV internal brackets, no other fatigue analyses were identified for the RPV internal components.

Table 3.1.2-1 lists the jet pump assemblies, the fuel support and control rod drive assemblies as

BSEP 05-0050 Enclosure I Page 81 of 87 TLAAs, evaluated for cumulative damage in accordance with 10 CFR54.21(c). Provide justification for not identifying these TLAAs in Section 4.3.2.

RAI 4.3-2 Response The statement in Section 4.3.2 is correct. The reason there are TLAAs for the RPV shroud support and RPV internal brackets is that these locations are integral parts of the RPV. They were analyzed for fatigue within the RPV stress report, as required for pressure retaining components by ASME Section III, Class 1 fatigue design rules.

Using the BSEPAMR methodology, operating temperatures for in-scope components were determined and compared to screening criteria which, if exceeded, indicate the component is exposed to thermal cycles which may have been analyzed for fatigue. The entries in Table 3.1.2-1, "Cracking due to thermal fatigue" and "TLAA, evaluated in accordance with 10CFR54.21(c)," were applied for each component that exceeded these operating temperature screening criteria. However, this does not automatically mean that a TLAA was identified for the component. Rather, it means that an evaluation was performed to determine whether or not a fatigue TLAA exists for the component. During the TLAA identification process, the design basis for the RPV internal components was reviewed to determine if fatigue analyses had been performed. No fatigue TLAAs were identified for the jet pump assemblies, the fuel support and control rod drive assemblies.

NRC RAI 4.6-1 Provide the design codes for the liner plate, torus downcomer/vent header and torus attached and SRV piping.

RAI 4.6-1 Response Unlike all other Mark I torus designs, the BSEP torus design utilizes a reinforced concrete structure with a coated carbon steel liner plate. The drywell and suppression chamber (i.e., the torus), including vent line, vent header and penetrations, are Class I structures, as defined in UFSAR Section 3.2.1.1. The torus liner plate was designed as part of the suppression chamber.

UFSAR Table 3-9, Item 10, provides the applicable design codes for the reactor containment (i.e., drywell and torus, including extension of drywell). Note 20 to Table 3-9 states that:

The design and construction of the portions of the containment not backed by reinforced concrete were in accordance with the applicable requirements specified in Specification 9527-01-15-1, ASME Code Section III (Subsection B), 1968 Edition with Summer, 1968 Addenda, Code Case 1330-1, and Code Case 1177-5. The design and construction of the portions of the containment backed by reinforced concrete were in accordance with the applicable requirements specified in Specification 9527-01-15-1 and ASME Code,Section VIII, 1968 Edition with Summer, 1968 Addenda.

BSEP 05-0050 Page 82 of 87 UFSAR Table 3-9 also shows that the Safety/Relief Valve (SRV) discharge piping and the various piping systems attached to the torus were originally designed in accordance with ANSI (USAS) B31.1.0, 1967 Edition, Power Piping Code.

UFSAR Section 6.2.1.1.2.2 provides additional Codes, Standards and Guides used in the design of the containment and internal structures that resulted from the Mark I Containment Program.

Structural design is based on the 1977 Edition of ASME Section m, Subsection ND, Addenda through Summer, 1977, which was also used for defining the containment design margin of safety for the shell, vent header system, and internal structures of the BSEP torus, as described in BSEP responses to NUREG-0661, "Mark I Containment Long Term Program Safety Evaluation Report," July 1980.

NRC RAI 4.6-2 State whether the liner plate/pool shell was evaluated for fatigue under the Mark I Containment Program Plant Unique Analysis. If not, provide the justification why a fatigue analysis was not required.

RAI 4.6-2 Response The torus liner plate/pool shell was not evaluated for fatigue under the Mark I Containment Program Plant Unique Analysis. The BSEP torus was designed as a reinforced concrete structure with a coated carbon steel liner plate. Refer to RAI 4.6-1 for applicable design requirements for the torus liner plate.

NRC RAI 4.6.1-1 The estimate of the total SRV actuations to occur over the 40-year plant life was based on the number of actual SRV actuations counted through 1981. Provide a statement indicating that the estimate remains valid and conservative based on actual SRV actuations counted through 2004.

RAI 4.6.1-1 Response The following tables summarize the SRV cycle projections and fatigue analyses for limiting components affected by SRV discharges. Also see Table 4.6-1 of the BSEP LRA, which includes the original 40-year design analysis, the 60-year design analysis, the maximum allowable values, and the 60-year projections based on RCPB Fatigue Monitoring Program data.

BSEP 05-0050 Page 83 of 87 si <I.I'TORUSDOWNCOME IEN. HEADER CUYSUMIARY- -:1 (LIMIT1NG CATION ONLY),.

ven Element Tota SR

-;.-- Condensation-

-I-- Chugging Total-.

t No RVu O iationFtgue ti U

F

_~Cce s~e Faf.iUage'sage 40-Year Design QUAD 36 2,000 0.286 0.000 0.150 0.436 60-Year Design QUAD 36 3,000 0.429 0.000 0.150 0.579 Maximum Allowable QUAD 36 5,944 0.850 0.000 0.150 1.000 60-Year Projection QUAD 36 1,644 0.235 0.000 0.150 0.385 The 40-year fatigue analysis of the limiting torus downcomer/vent header location was based upon a conservative estimate of 400 SRV actuation events that were projected to occur in 40 years, based upon the actual SRV actuation events that had been counted through 1981. Each SRV event was assumed to produce five individual cycles to account for reseating and repeat lifting of the SRV, for a total of 2,000 cycles.

The 60-year design fatigue analysis used a factor of 1.5 applied to the 40-year SRV cycles, resulting in 600 actuation events, and 3,000 total cycles. The maximum allowable projection shows that 5,944 SRV cycles could be tolerated without exceeding a CUF value of 1.0.

The 60-year projection is based upon RCPB Fatigue Monitoring Program data for transients associated with SRV operation, including plant startups and plant trips. Only 1,644 SRV cycles are projected to occur in 60 years, resulting in fatigue usage of only 0.385. This demonstrates that the 60-year CUF estimates remain valid and conservative.

The 60-year projection was based upon the following assumptions:

1. When SRV tests are performed during each plant startup, a single SRV cycle occurs. The RCPB Fatigue Monitoring Program tracks plant startups, and the 60-year projected number of Unit 2 plant startups is 244 which is bounding for both units, resulting in 244 individual SRV cycles. See Table 4.3-1 of the BSEP LRA.

2. When a scram occurs, each SRV may lift and reseat for up to 5 cycles per event.

The RCPB Fatigue Monitoring Program also tracks reactor scrams, and the 60-year projection for all types of reactor scrams combined is 280 for Unit 2, which is bounding. Since each scram may result in 5 SRV cycles, 1400 SRV cycles are projected for 60 years for each SRV due to scrams. The combined total projected number of cycles is 1644, which would result in a CUF value of only 0.385.

The 40-year fatigue analysis for the SRV discharge piping was also based upon 2,000 SRV cycles. See Table 4.6-2 of the BSEP LRA. However, the 60-year fatigue analysis for the SRV

BSEP 05-0050 Page 84 of 87 discharge piping and torus-attached piping was conservatively adjusted by a factor of 2.0. The estimated number of SRV cycles used in these 60-year fatigue analyses for BSEP components remains valid and conservative based on monitoring of plant transients which are directly related to SRV actuations.

4:-12 INCH SRV DIS CHA-RGE XINE CUF VALUES; -

1 1,'

~

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IN O'.'.CATION' l;',-.

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I iSRVCycles

-CUF 40-Year Design 2,000 0.486 60-Year Design 4,000 0.972 Maximum Allowable 4,115 1.000 60-Year Projection 1,644 0.399 Since the RCPB Fatigue Monitoring Program tracks plant startups and plant scrams which result in SRV cycles, direct tracking of SRV cycles is not necessary. In addition, these cycles are not directly monitored because the components affected by these cycles are not considered limiting, and are not expected to approach a CUF value of 1.0 during either the 40-year or 60-year life of the plant.

NRC RAI 4.6.1-2 This section refers to an "augmented" Class 2/3 fatigue methodology that was developed to account for cyclic mechanical loads. Provide a description of this methodology, or alternatively, provide an accessible reference where this methodology may be found.

RAI 4.6.1-2 Response Report MPR-751, "Mark I Containment Program Augmented Class 2/3 Fatigue Evaluation Method and Results for Typical Torus-Attached and SRV Piping Systems, November," 1982; prepared by MPR Associates, Washington, D.C., provides a description of this methodology. A copy of this report was submitted to the NRC as Attachment RAI 13 to BSEP letter to the NRC (Serial: LAP-83416), "Mark I Containment Program Responses to NRC Requests for Information," dated September 15, 1983.

BSEP 05-0050 Page 85 of 87 NRC Audit Question B.2.15-1a (Supplemental Response)

At the beginning of the AMR on-site audit, the project team discussed the applicant's One-Time Inspection Program with the applicant, relating to its commitment to inspect Class 1 small bore piping. As a result, the applicant committed in its latest response to question B.2.15-1 to inspect Class 1 small bore piping, consistent with the GALL Report. The text of the response is as follows:

BSEP will revise the One Time Inspection Program to include verification of aging management program effectiveness on less than four inch piping and fittings within ASME Code Class 1 boundaries.

The BSEP One-Time Inspection Program will be revised to include the following description of how cracking will be detected. The inspection includes a representative sample of the population, and, where practical, focuses on the bounding or lead components most susceptible to aging due to time in service, severity of operating conditions, and lowest design margin. For small-bore piping, actual inspection locations are based on physical accessibility, exposure levels, NDE techniques, and locations identified in Nuclear Regulatory Commission (NRC) Information Notice (IN) 97-46, as applicable. Combinations of NDE, including visual, ultrasonic, and surface techniques, are performed by qualified personnel following procedures consistent with the ASME Code and 10 CFR 50, Appendix B. For small-bore piping less than NPS 4 inches, including pipe, fittings, and branch connections, a plant-specific destructive examination of replaced piping due to plant modifications or NDE that permits inspection of the inside surfaces of the piping will be performed to ensure that cracking has not occurred.

Follow-up of unacceptable inspection findings includes expansion of the inspection sample size and locations. With respect to inspection timing, the one-time inspection is to be completed before the end of the current operating license. The applicant may schedule the inspection in such a way as to minimize the impact on plant operations.

However, the inspection is not to be scheduled too early in the current operating term, which could raise questions regarding continued absence of aging effects prior to and near the extended period of operation.

BSEP credits the Water Chemistry Program and ASME Section XI Subsection IWB, IWC and IWD Program (for leakage inspections) for aging management of cracking in less than 4" NPS Class 1 piping components. These components will be subject to physical inspections for leakage under the latter program. Additionally, One Time Inspection Program will be used, as described above, to verify the effectiveness of these programs.

Upon inclusion of small bore piping in the BSEP One Time Inspection Program as described above, the program will be consistent with the program description found in NUREG 1 800, Aging Management Program XI.M32. Details regarding the implementation of the one time inspections, including identification of specific sampling techniques and inspection locations, will be formalized prior to implementation of the program.

BSEP 05-0050 Page 86 of 87 The project team accepted the applicant's response to question B.2.15-1. However, the project team did NOT request and the applicant did not identify the required revisions to the BSEP LRA, in order to be consistent with this new commitment.

Therefore, the applicant is requested to augment its response to question B.2.15-1, to identify all required revisions to the BSEP LRA, in order to be consistent with its new commitment. As a minimum, the applicant should address LRA revisions to Section 3.1.2.2.4.1; Tables 3.1.2-1 through 3.1.2-5, including any applicable generic and plant-specific note revisions; Appendix A Section A.1.1.15; and Appendix B Section B.2.15. The applicant should also consider whether its new commitment affects any AMRs in LRA Sections 3.2, 3.3 and 3.4, and identify any needed revisions to these LRA sections also.

AQ B.2.15-la Supplemental Response The use of the One-Time Inspection Program for aging management of small-bore Class 1 piping inspections impacts the BSEP LRA as follows:

Section 3.1:

Table 3.1.1 -The discussion of aging management of cracking of small bore reactor coolant system and connected piping in 3.1.1-07 will specify the ASME Section XI, Inservice Inspection, Subsections IWB, IWC and IWD Program and the Water Chemistry Program for aging management, and use the One-Time Inspection Program for verification of program effectiveness, consistent with the recommendations of GALL.

Section 3.1.2.2.4.1 -The discussion will no longer reference or credit RI-ISI for aging management. BSEP credits the ASME Section XI, Inservice Inspection, Subsections IWB, IWC and IWD Program and the Water Chemistry Program for aging management, and use the One-Time Inspection Program for verification of program effectiveness, consistent with the recommendations of GALL.

AMR Tables 3.1.2-1 and 3.1.2-5 (Tables 3.1.2-2, -3 and -4 have no small bore Class 1 piping line items.) -AMR line items addressing small bore Class 1 piping will be revised to reflect Water Chemistry, ASME Section XI, Inservice Inspection, Subsection IWB, IWC and IWD and One-Time Inspection Programs for aging management of cracking due to thermal and mechanical loading and SCC. Standard Note "B" applies, since the Water Chemistry Program has exceptions to GALL.

Note 118 is no longer applicable.

Section 3.2:

AMR Tables 3.2.2-3, 3.2.2-5, 3.2.2-7 -AMR line items addressing small bore Class 1 piping will be revised to reflect Water Chemistry, ASME Section XI, Inservice Inspection, Subsection IWB, IWC and IWD, and One-Time Inspection Programs for aging management of cracking due to thermal and mechanical loading and SCC.

Standard Note "B" applies, since the Water Chemistry Program has exceptions to GALL.

Note 226 is no longer applicable.

Sec Ap, BSEP 05-0050 Page 87 of 87

-tion 3.3:

AMR Tables 3.3.2-1 and 3.3.2 AMR line items addressing small bore Class 1 piping will be revised to reflect Water Chemistry, ASME Section XI, Inservice Inspection, Subsection IWB, lWC and IWD, and One-Time Inspection Programs for aging management of cracking due to thermal and mechanical loading and SCC.

Standard Note "B" applies, since the Water Chemistry Program has exceptions to GALL.

Note 348 is no longer applicable.

pendix A:

A.1.1.1 -As noted in the response to Audit Question B.2.1-1, the description of the ASME Section XI, Inservice Inspection, Subsections IWB, IWC and IWD Program will no longer credit RI-ISI in aging management.

A.1.1.15 - As noted in the response to Audit Question B.2.15-1, the description of the One Time Inspection Program will reflect that the One-Time Inspection Program includes inspection of small bore Class 1 piping for cracking.

pendix B:

B.2. 1 - The Description of the ASME Section XI, Inservice Inspection, Subsections IWB, IWC and IWD Program will no longer credit RI-ISI in aging management.

B.2.15 -The Description of the ASME Section XI, Inservice Inspection, Subsections IWB, IWC and IWD Program will no longer credit RI-ISI in aging management.

One-Time Inspection Program activities will include an activity for inspection of small bore Class I piping. The exception noted regarding inspection of small bore Class 1 piping will be deleted, such that the program will be considered consistent with GALL.

Ap]

BSEP 05-0050 Page 1 of 5 Brunswick Steam Eletri P1 t(BSEP) License Renewal Co

iment, evio 3 License Renewal' L

Commtmen Subect Appedix,

-Scdoe~or Commitment Section Quality Assurance (QA)

A. 1.1 Prior to the period of extended operation, the elements of corrective action, confirmation process, and administrative controls in the BSEP QA Program will be applied to required aging management activities for both safety related and non-safety related structures and components subject to aging management review.

Flow-Accelerated A. 1.1.5 Prior to the period of extended operation, the BSEP FAG susceptibility analyses will be updated to include Corrosion (FAC) Program additional components potentially susceptible to FAC.

Bolting Integrity Program A. 1.1.6 Prior to the period of extended operation, a precautionary note will be added to plant bolting guidelines to limit the sulfur content of compounds used on bolted connections.

Open-Cycle Cooling Water A. 1.1.7 Prior to the period of extended operation, the Open-Cycle Cooling Water System Program will be enhanced to System Program require that: (1) Program scope include portions of the Service Water (SW) System credited in the Aging Management Review, including non-safety related piping, (2) the Residual Heat Removal (RJR) Heat Exchangers will be subject to eddy current testing with results compared to previous testing to evaluate degradation and aging, (3) A representative sampling of SW Pump casings be inspected, (4) Program procedures be enhanced to include verification of cooling flow and heat transfer effectiveness of SW Pump Oil Cooling Coils, inspections associated with SW flow to the Diesel Generators (including inspection of expansion joints),

and inspection and replacement criteria for RHR Seal Coolers, (5) Piping inspections will include locations where throttling or changes in flow direction might result in erosion of copper-nickel piping, and (6) Performance testing of the RHR and Emergency Diesel Generator Jacket Water heat exchangers will be performed to verify heat transfer capability.

Closed-Cycle Cooling A.1.1.8 Prior to the period of extended operation, Closed-Cycle Cooling Water System Program activities will be Water System Program enhanced to assure that Preventive Maintenance activities include inspections of DG combustion air intercoolers and heat exchangers.

Inspection of Overhead A.1.1.9 Administrative controls for the Program will be enhanced, prior to the period of extended operation to: (1) include Heavy Load and Light in the Program all cranes/platforms within the scope of License Renewal, (2) specify an annual inspection Load Handling frequency for the Reactor Building Bridge Cranes and the Intake Structure Gantry Crane, and every fuel cycle for the Refuel Platforms, (3) allow use of maintenance crane inspections as input for the condition monitoring of License Renewal cranes, (4) require maintenance inspection reports to be forwarded to the responsible engineer, and (5) include inspection of structural component corrosion and monitoring crane rails for abnormal wear.

Fire Water System Program A.1.1.1I Prior to the period of extended operation, Fire Water System Program administrative controls will be enhanced to require assessing results from the initial 40-year service life tests and inspections to determine whether a representative sample of such results has been collected and whether expansion of scope and use of alternate testlinspection methods are warranted.

BSEP 05-0050 Page 2 of 5

. Brunswick Steam Electric Plant (BSEP) License Renewal Commitment esion 3; icense Renewa I -

ei A,

coe of Comitment Commitment Subject St Aboveground Carbon Steel A. 1.1.12 The Aboveground Carbon Steel Tanks Program is a new aging management program that will be implemented Tanks Program prior to the period of extended operation.

Fuel Oil Chemistry A.1.1.13 Prior to the period of extended operation: (1) Fuel Oil Chemistry Program administrative controls will be Program enhanced to add a requirement to trend data for water and particulates, (2) the condition of the in-scope fuel oil tanks will be verified by means of thickness measurements under the One-Time Inspection Program, and (3) an internal inspection of the Main Fuel Oil Storage Tank will be performed under the One-Time Inspection Program.

Reactor Vessel Surveillance A.1.1.14 The Reactor Vessel Surveillance Program will be enhanced to ensure that any additional requirements that result Program from the NRC review of Boiling Water Reactor Vessel Internals Program (BWRVIP)-1 16 are addressed prior to the period of extended operation.

One-Time Inspection A. 1.1.15 This is a new aging management program that requires procedural controls for implementation and tracking of Program One-Time Inspection Program activities. The One-Time Inspection Program will be implemented prior to the period of extended operation.

Selective Leaching of A.1.1.16 The Selective Leaching of Materials Program is a new aging management program that requires a sample Materials Program population of susceptible components to be selected for inspection. The Selective Leaching of Materials Program will be implemented prior to the period of extended operation.

Buried Piping and Tanks A. 1.1.17 The Buried Piping and Tanks Inspection Program is a new aging management program that will be implemented Inspection Program prior to the period of extended operation and will include procedural requirements to (1) ensure an appropriate as-found pipe coating and material condition inspection is performed whenever buried piping within the scope of the Buried Piping and Tanks Inspection Program is exposed, or, as a minimum, once every 10 years, (2) add precautions concerning excavation and use of backfill to the excavation procedure to include precautions for, License Renewal piping, (3) add a requirement that coating inspection shall be performed by qualified personnel to assess its condition, and (4) add a requirement that a coating engineer or other qualified individual should assist in evaluation of any coating degradation noted during the inspection.

ASME Section XI, A. 1.1.20 Prior to the period of extended operation, the ASME Section XI, Subsection IWF Program will be enhanced to Subsection IWF Program include the torus vent system supports within the scope of the Program.

Masonry Wall Program A. 1.1.22 Prior to the period of extended operation, the administrative controls for the Masonry Wall Program will be enhanced to require inspecting all accessible surfaces of the walls for evidence of cracking.

BSEP 05-0050 Page 3 of 5

-. Brunswick Steam Electric Plant (BSEP) License Renewal Commitments, Revision 3-:

'Licene Renewal LA cpeo omtmn Commitmenit-Subject, d A, m

Section' Structures Monitoring A.1.1.23 Prior to the period of extended operation, the Structures Monitoring Program will be enhanced to: (1) identify Program License Renewal systems managed by the Program and inspection boundaries between structures and systems, (2) require notification of the responsible engineer regarding availability of exposed below-grade concrete for inspection and require that an inspection be performed, (3) identify specific license renewal commodities and inspection attributes, (4) require responsible engineer review of groundwater monitoring results, (5) specify that an increase in sample size for component supports shall be implemented (rather than should be) commensurate with the degradation mechanisms found, (6) improve training of system engineers in condition monitoring of structures, (7) include inspections of the submerged portions of the Service Water Intake Structure on a frequency not to exceed five years, (8) specify an annual groundwater monitoring inspection frequency for concrete structures, and (9) specify the inspection frequency for the Service Water Intake Structure and Intake Canal to not exceed five years. Following enhancement, the Structures Monitoring Program will be consistent with the

-corresponding program described in NUREG-1801.

Protective Coating A. 1.1.24 Prior to the period of extended operation, the Protective Coating Monitoring an Maintenance Program Monitoring an administrative controls will be enhanced to: (1) add a requirement for a walk-through, general inspection of Maintenance Program containment areas during each refueling outage, including all accessible pressure-boundary coatings not inspected under the ASME Section XI, Subsection IWE Program, (2) add a requirement for a detailed, focused inspection of areas noted as deficient during the general inspection, (3) assure that the qualification requirements for persons evaluating coatings are consistent among the Service Level I coating specifications, inspection procedures, and application procedures, and meet the requirements of ANSI N 101.4, "Quality Assurance for Protective Coatings Applied to Nuclear Facilities," and (4) document the results of inspections and compare the results to previous inspection results and to acceptance criteria.

Electrical Cables and A. 1.1.25 The Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Connections Not Subject to Program is a new aging management program that will be implemented prior to the period of extended operation.

10 CFR 50.49 Environ-mental Qualification Requirements Program Electrical Cables and A. 1.1.26 The Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Connections Not Subject to Used in Instrumentation Circuits Program is a new aging management program that will be implemented prior to 10 CFR 50.49 Environ-the period of extended operation.

mental Qualification Requirements Used in Instrumentation Circuits Program

BSEP 05-0050 Page 4 of 5 Brunswick Steam Electric Plant (BSEP) License Renewal Commitments, RevisIon 3.

Licen Renewal i

RA.

Commitment Subject Apni

,-Soeo omtin ISec'tio'n Inaccessible Medium A.1.1.27 The Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Voltage Cables Not Subject Requirements Program is a new aging management program that will be implemented prior to the period of to 10 CFR 50.49 Environ-extended operation.

mental Qualification Requirements Program Reactor Coolant Pressure A. 1.1.28 Prior to the period of extended operation, the Program will be enhanced to: (I) expand the Program scope to Boundary (RCPB) Fatigue include an evaluation of each reactor coolant pressure boundary component included in NUREG/CR-6260, Monitoring Program (2) provide preventive action requirements including requirement for trending and consideration of operational changes to reduce the number or severity of transients affecting a component, (3) include a requirement to reassess the locations that are monitored considering the RCPB locations that were added to the Program scope, (4) specify the selection criterion to be locations with a 60-year CUF value (including environmental effects where applicable) of 0.5 or greater, other than those identified in NUREG/CR-6260, (5) address corrective actions for components approaching limits, with options to include a revised fatigue analysis, repair or replacement of the component, or in-service inspection of the component (with prior NRC approval), and (6) address criteria for increasing sample size for monitoring if a limiting location is determined to be approaching the design limit.

Reactor Vessel and A. 1.1.30 Prior to the period of extended operation, the Reactor Vessel and Internals Structural Integrity Program will be Internals Structural enhanced to: (1) incorporate augmented inspections of the top guide using enhanced visual examination that will Integrity Program focus on the high fluence region and (2) establish inspection criteria for the VT-3 examination of the Core Shroud Repai Bracets.

Systems Monitoring A. 1.1.31 Prior to the period of extended operation, a procedure will be developed to implement: 1) inspection of in-scope Program License Renewal components for identified aging effects, 2) guidelines for establishing inspection frequency requirements, 3) listing of inspection criteria in checklist form, 4) recording of extent of condition during system walkdowns and 5) addressing of appropriate corrective action(s) for degradations discovered.

Preventive Maintenance A. 1.1.32 Prior to the period of extended operation, preventive maintenance activities will be incorporated into the PM (PM) Program Program, as needed, to satisfy aging management reviews of components that rely on the PM Program for management of aging effects.

Phase Bus Aging A. 1.1.33 The Phase Bus Aging Management Program is a new aging management program that will be implemented prior Management Program to the period of extended operation.

BSEP 05-0050 Page 5 of 5 Brunswick Steam Ele'itric PIant (BSEP) License Renewal Commitmen ts, evisi 3

Lic e

LRA, Reseenewal AcensSop

-Comitmnit Subjkect A

Scope ofCommtment

.Section Fuel Pool Girder Tendon A. 1.1.34 Prior to the period of extended operation, the Fuel Pool Girder Tendon Inspection Program will be enhanced to:

Inspection Program (1) specify inspection frequencies, numbers of tendons to be inspected, and requirements for expansion of sample size, (2) identify test requirements and acceptance criteria for tendon lift-off forces, measurement of tendon elongation, and determination of ultimate strength, (3) specify inspections for tendons, tendon anchor assemblies, surrounding concrete, and grease, (4) require prestress values to be trended and compared to projected values, and (5) identify acceptable corrective actions for tendons that fail to meet testing criteria.

Time Limited Aging A.1.2.1.3 P-T limit curves for the period of extended operation will be submitted for NRC review andFapproval in Analysis (TLAA) -RPV accordance with the license amendment process at least one year prior to expiration of the 32 EFPY P-T limit Operating Pressure-curves that are currently approved in the Technical Specifications.

Temperature (P-T) Limits New commitment TLAA - Core Plate Plug A. 1.2.1.7 Management of Core Plate Plug Spring Stress Relaxation will be performed by means of the Reactor Vessel and Spring Stress Relaxation A.1.1.30 Internals Structural Integrity Program.

TLAA-Fuel Pool Girder A. 1.2.6 Prior to the period of extended operation, a Fuel Pool Girder Tendon Inspection Program will be implemented to Tendon Loss of Prestress A. 1.1.34 assure design basis anchor forces required for the tendons to perform their intended function will continue to be maintained.

TLAA - Torus Component A. 1.2.8 Prior to the period of extended operation, measurements are planned, using the One-Time Inspection Program, to Corrosion Allowance A.1.1.15 verify by volumetric measurements the actual rate of corrosion of the supports and platform steel in the Torus.