Text

Response to Request for Additional Information - License Renewal
	ML051720468
Person / Time
Site:	Brunswick
Issue date:	06/14/2005
From:	Gannon C; Progress Energy Co
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	BSEP 05-0071, TAC MC4639, TAC MC4640
	Download: ML051720468 (59)
	v • d • e

Cornelius J. Gannon Brunswick Nuclear Plant Progress Energy Carolinas. Inc.

June 14, 2005 SERIAL: BSEP 05-0071 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, "Requests for Additional Information (RAIs) for the Review of the Brunswick Steam Electric Plant, Units I and 2, License Renewal Application," dated May 18, 2005 (ML051380587)

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 May 18, 2005, the Nuclear Regulatory Commission (NRC) provided requests for additional information (RAIs) concerning the BSEP License Renewal Application. to this letter provides responses to the NRC RAIs. Also, this enclosure includes information that supplements responses to previous NRC RAIs and provides an applicant-identified revision to the License Renewal Application. The specific supplemental information is identified in Enclosure 1. 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.

P.O.

Box 10429 Southport. NC 28461 T> 910.457.3698 k\\ l F> 910.457.28031

Document Control Desk BSEP 05-0071 / Page 2 I declare, under penalty of perjury, that the foregoing is true and correct. Executed on June 14, 2005 Sincerely,

.Gannon MHF/mhf

Enclosures:

1. Responses to Requests forAdditional Information dated May 18, 2005

2. BSEP License Renewal Commitments, Revision 5

Document Control Desk BSEP 05-0071 / Page 3 cc:

U. S. Nuclear Regulatory Commission, Region II ATTN: 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 ATTN: Mr. Richard L. Emch (Mail Stop OWFN IlFI) 11555 Rockville Pike Rockville, MD 20852-2738 U. S. Nuclear Regulatory Commission A'ITN: 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 05-0071 Page 1 of 51 Responses to Request for Additional Information dated May 18, 2005

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. 1 and 2, to extend the terms of their operating licenses an additional 20 years beyond the current expiration dates.

By letter dated May 18, 2005, the Nuclear Regulatory Commission (NRC) provided requests for additional information (RAIs) concerning the LRA. Responses to the RAIs are provided in this enclosure.

Also, this enclosure includes information that supplements responses to previous NRC RAIs and provides an applicant-identified revision to the LRA. Specifically, the supplemental information addresses the following:

Previous RAI/Item Letter Transmitting Previous Response RAI 2.3.3.7-9a and 9b PEC letter to NRC (Serial: BSEP 05-0050), dated May 4, 2005.

RAI 3.5-8 PEC letter to NRC (Serial: BSEP 05-0050), dated May 4, 2005.

RAI 4.2-2 PEC letter to NRC (Serial: BSEP 05-0050), dated May 4, 2005.

RAI 4.7.4-1 PEC letter to NRC (Serial: BSEP 05-0044), dated March 31, 2005.

RAI 4.7.4-2 PEC letter to NRC (Serial: BSEP 05-0044), dated March 31, 2005.

Applicant-Identified Item Not applicable.

Table of Contents Pate Table of Acronyms and Abbreviations..........................

2 NRC RAI 2.3.2.7-1...........................

3 NRC RAI 2.3.3.29-1...........................

4 NRC RAI 2.5-1...........................

7 NRCRAI2.5.1-1...........................

7 NRC RAI 2.1.4.2-1...........................

7 NRC RAI 3.1.2.3.1.1-1...........................

8 NRC RAI 3.1.2.3.1.2-1..........................

10 NRC RAI 3.1.2.3.1.2-2..........................

10 NRC RAI 3.1.2.3.3-1..........................

11 NRC RAI 3.1.2.3.3-2..........................

13 NRC RAI 3.1.2.3.3-3..........................

13 NRC RAI 3.1.2.3.3-4..........................

14 NRC RAI 3.6.2.3-1..........................

14 NRC RAI 3.6.2.3-2..........................

16 NRC RAI 3.6.2.3-3..........................

16 NRC RAI 3.6.2.3-4..........................

17

BSEP 05-0071 Page 2 of 51 NRC RAI 3.6.2.3-5.............................................

18 NRC RAI 3.6.2.3-6.............................................

19 NRC RAI 4.2.1-1.............................................

20 NRC RAI B.2.28-1.............................................

20 NRC RAI B.2.28-2.............................................

24 NRC RAI B.2.28-3.............................................

25 NRC RAI B.2.28-4.............................................

26 NRC RAI B.2.28-5.............................................

27 NRC RAI B.2.28-6.............................................

27 NRC RAI B.2.28-7/3.1.2.3.1.2-3.............................................

30 NRC RAI B.2.28-8.............................................

32 NRC RAI B.2.28-9.............................................

33 NRC RAI B.2.28-10.............................................

34 NRC RAI B.2.28-11.............................................

34 NRC RAI B.2.28-12/4.2-3.............................................

38 NRC RAI B.2.28-13/4.3-1.............................................

38 NRC RAI B.2.28-14.............................................

39 NRC RAI B.2.28-15.............................................

40 NRC RAIs 2.3.3.7-9a and 2.3.3.7-9b (Supplemental Response)........................................... 44 NRC RAI 3.5-8 (Supplemental Response).............................................

45 NRC RAI 4.2-2 (Supplemental Response).............................................

45 NRC RAI 4.7.4-1 (Supplemental Response).............................................

47 NRC RAI 4.7.4-2 (Supplemental Response).............................................

48 Applicant-Identified Item (Auxiliary Heat Exchangers).............................................

50 The following table defines acronyms and abbreviations used in this enclosure.

TABLE OF ACRONYMS AND ABBREVIATIONS AP Delta-P, i.e., Differential Pressure AAI Applicant Action Item ACSR Aluminum Conductor Steel Reinforced AERM Aging Effect Requiring Management AHC Access Hole Covers AMP Aging Management Program AMR Aging Management Review 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 Project CAC Containment Atmosphere Control CP&L Carolina Power & Light Company CRD Control Rod Drive CRDH Control Rod Drive Housing CRDM Control Rod Drive Mechanism CUF Cumulative Usage Factor DOE Department of Energy EFPY Effective Full Power Years

BSEP 05-0071 Page 3 of 51 TABLE OF ACRONYMS AND ABBREVIATIONS EPRI Electric Power Research Institute EPU Extended Power Uprate EQ Environmental Qualification EVT Enhanced Visual Test FSAR Final Safety Analysis Report FSER Final Safety Evaluation Report GALL Generic Aging Lessons Learned (the GALL Report is NUREG-1 801)

GE General Electric Company HPCI High Pressure Coolant Injection HVAC Heating, Ventilation, and Air Conditioning IASCC Irradiation Assisted Stress Corrosion Cracking 1CM In-Core Monitoring IGSCC Intergranular Stress Corrosion Cracking ISI Inservice Inspection LOCA Loss of Coolant Accident LRA License Renewal Application MeV Million Electron Volts MOD Motor Operated Disconnect NESC National Electrical Safety Code NRC Nuclear Regulatory Commission NUMARC Nuclear Management and Resources Council OTI One-Time Inspection PCB Power Circuit Breaker PEC Progress Energy Carolinas PM Preventive Maintenance RAI Request for Additional Information RCIC Reactor Core Isolation Cooling RV Reactor Vessel RV&ISIP Reactor Vessel and Internals Structural Integrity Program SAT Startup Auxiliary Transformer SBO Station Blackout SCC Stress Corrosion Cracking SER Safety Evaluation Report SGTS Standby Gas Treatment System SIL Service Information Letter SLC Standby Liquid Control SWIS Service Water Intake Structure TLAA Time-Limited Aging Analysis UAT Unit Auxiliary Transformer UFSAR Updated Final Safety Analysis Report UT Ultrasonic Test NRC RAI 2.3.2.7-1 Brunswick Steam Electric Plant, Units 1 and 2 SGTS is described in LRA Section 2.3.2.7 and on LRA Drawings F-40073-LR, Sheet 3 (BSEP, Unit 1), F-04073-LR, Sheet 3 (BSEP, Unit 2), and Common LRA Drawings D-04104-LR and F-02314-LR (BSEP, Units 1 and 2), LRA Table 2.3.2-6, "Component/Commodity Groups Requiring Aging Management Review and Their Intended Functions: Standby Gas Treatment System," and LRA Table 3.2.2-6, "Engineered Safety

BSEP 05-0071 Page 4 of 51 Features - Summary of Aging Management - Evaluation Standby Gas Treatment System (SGTS)." However, these documents do not contain all the components of the SGTS as highlighted on the drawings. For example, while the tables list duct work (equipment frames and housing), filters (housing and supports), filters (elastomers seals), etc., they do not list exhaust fan housings, valve bodies, and screens for exhaust and intake structure(s), just to name a few.

Clarify whether these components and all other applicable components of the system, are within the scope of license renewal in accordance with 10 CFR 54.4(a), and subject to an Aging Management Review (AMR) in accordance with 10 CFR 54.21(a)(1). If these components are excluded from the scope of license renewal and not subject to an AMR, provide justification for the exclusion.

RAI 2.3.2.7-1 Response The SGTS is safety related, and components required to supports its safety related function are in the scope of license renewal in accordance with 10 CFR 54.4(a). This includes fans and filters, valves, screens at the system intake, as well as ductwork / dampers. Passive, long-lived components are subject to AMR under 10 CFR 54.21(a)(1), and include the filter housings, fan housings, screens, and valve bodies.

The SGTS boundaries at BSEP are fairly limited, generally encompassing the SGTS exhaust fans, filters, and piping and valves. Line items for each of these components are represented in the LRATable 3.2.2-6. Specifically, fan housings are included under "Ductwork (equipment frames and housings)," and valve bodies are addressed under "Standby Gas Treatment (Boiling Water Reactor) (Valves)." The SGTS System interfaces with the Reactor Building Ventilation System and the Containment Atmospheric Control (CAC) System to accomplish its intended functions. The debris screens on the lines from the Drywell and Suppression Chamber are part of the CAC System, and are addressed in LRA Table 3.2.2-2 under "Piping Specialties," with the M-2 intended function. Reactor Building dampers required to isolate in support of SGTS are part of the Reactor Building Ventilation System and are addressed in LRA Table 3.3.2-22.

NRC RAI 2.3.3.29-1 LRA Section 2.3.3.29, "HVAC Service Water Intake Structure," states as follows:

The HVAC Service Water Intake Structure (SWIS) consists of two 100%-capacity independent ventilation systems (one for each unit). Each independent system contains discharge fans, discharge dampers, associated electrical equipment, instrumentation and controls, and supply air openings with bird screens.

The HVAC SWIS is in the scope of License Renewal, because it contains components that are safety-related and are relied upon to remain functional during and following design basis events.

The system is necessary to control the environment in safety-related equipment areas so that contained safety-related equipment can perform its safety-related function.

BSEP 05-0071 Page 5 of 51 However, the applicant chose not to provide applicable LRA drawing(s) and LRA table(s) for the HVAC SWIS described in LRA Section 2.3.3.29. The licensee stated that the fans are not ducted and do not have an associated pressure boundary.

The HVAC SWIS provides a safety-related cooling function (for the intake structure) to control the environment in safety-related equipment areas so that contained safety-related equipment can perform its safety-related function. Clarify whether system discharge fans and associated housings, discharge dampers and associated housings, and supply air openings with bird screens should be within the scope of license renewal in accordance with 10 CFR 54.4(a), and subject to an AMR in accordance with 10 CFR 54.21(a)(1). If they are, they should be included in appropriate LRA tables. If they are excluded from the scope of license renewal and not subject to an AMR, provide justification for the exclusion.

RAI 2.3.3.29-1 Response SWIS fans 1-VA-lA-EF-SWIS and 2-VA-2A-EF-SWIS, including fans, dampers, bird screens, and mountings/supports are within the scope of license renewal in accordance with 10 CFR 54.4(a). The SWIS fans, dampers, and bird screens are not ducted, but are mounted in a shrouded housing directly into an opening in the SWIS wall. Considering this configuration, the initial aging management approach reflected in the LRA was to consider that the fans and dampers were active, and the passive features were essentially mounting/support features and would be addressed as part of the SWIS building structure. BSEP has revised this approach to specifically address the subcomponents that the NRC has identified (i.e., fan and damper housings and bird screens) in the AMR for SWIS Auxiliary Systems.

This revision modifies the discussion for the Heating, Ventilation, and Air Conditioning (HVAC) system for the SWIS described in LRA Section 2.3.3.29 to reflect that the system includes fan and damper housings, bird screens, and mountings/supports that are passive, long-lived features requiring AMR in accordance with 10 CFR 54.21(a)(1). Accordingly, three line items (i.e., one for fan housings, one for damper housings, and one for bird screens) will be added to the AMR associated with LRA Table 3.3.2-24. These line items are provided on the following page.

The Systems Monitoring Program is described in LRA Subsection B.2.29, and includes criteria applicable to the components and aging effects addressed herein. Structural supports and mounting of the fan/damper housing will continue to be addressed as structural commodities within the SWIS building structure in LRATable 3.5.2-7, with the Structures Monitoring Program specified for aging management.

BSEP 05-0071 Page 6 of 51 Additional line items to be added to LRA Table 3.3.2 HVAC SWIS System:

Component Intended Ag ing Aging Management NUREG-1801 Table 1 Commodity Function Material Environment Requiring PormVolume 2

Ie oe Management PormItem Ie Duct (Equipment M-1 Carbon Outdoor Air Loss of Material Systems Monitoring J

Frames and Steel (External) due To General Housing)

Corrosion Outdoor Air Loss of Material Systems Monitoring J

(Internal) due To General Corrosion Duct (Debris M-2 Carbon Outdoor Air Loss of Material Systems Monitoring J

Screens)

Steel (External) due To General Corrosion Fans (Pressure M-1 Carbon Outdoor Air Loss of Material Systems Monitoring J

Retaining Steel (External) due To General Housing)

Corrosion Outdoor Air Loss of Material Systems Monitoring J

(Internal) due To General Corrosion

BSEP 05-0071 Page 7 of 51 NRC RAI 2.5-1 In this section you have stated that the assessment of electrical racks, panels, cabinets, cable trays, conduit and their supports is documented in Section 2.4. However, it is not clear to the staff why these components are not included in an aging management program (AMP). Please clarify.

RAI 2.5-1 Response These items are screened as civil commodities in Section 2.4 of the LRA. Electrical Racks are addressed within the "Instrument Rack" commodity group. Panels and Cabinets are addressed within the "Electrical Enclosure" commodity group. Cable Trays & Conduits are addressed within the "Cable Trays & Conduits" commodity group. Supports are addressed within the "Electrical Supports" commodity group. The subject commodity groups are located, as applicable, in Tables 2.4-1 thru 2.4-15 of the LRA. The AMP for each civil commodity is located by structure under the associated commodity group in Tables 3.5.2-X of the LRA, as applicable.

NRC RAI 2.5.1-1 It is not clear to the staff why electrical racks, panels, cabinets, junction boxes, switchyard bus connections and transmission conductors connections are not included in the Electrical I&C component commodity groups table. Please clarify.

RAI 2.5.1-1 Response As discussed in Section 2.5 of the LRA, electrical racks, panels, cabinets, cable trays, conduit, and their supports are civil items whose assessment is documented in Section 2.4 of the LRA.

Also, see the response to RAI 2.5-1 above.

The connections associated with the commodity groups "Switchyard Bus" and "Transmission Conductors" are included in these commodity groups. The terminology shown in the table was selected for consistency with previous License Renewal applications, and to standardize electrical/I&C component commodity group terminology. Connections were evaluated as part of the AMR for the commodity groups. Switchyard bus connections were evaluated as shown in the LRA under plant-specific note 607 of Table 3.6.2-1, while transmission conductor connections were evaluated as shown in the LRA under plant-specific note 608 of Table 3.6.2-1.

NRC RAI 2.1.4.2-1

a. Are there any underground power circuits used in the station blackout (SBO) recovery paths?

If so, were they identified as requiring an AMR? If not, please explain.

BSEP 05-0071 Page 8 of 51

b. Provide a detailed description of the SBO recovery path.

c. Is the motor operated disconnect (MOD) qualified as a first breaker in the SBO recovery path?

RAI 2.1.4.2-1 Response

a. There are no underground power circuits used in the SBO recovery path.

b. There are two offsite sources of auxiliary power available when recovering from an SBO event. The first (i.e., preferred) source of offsite power is via the Startup Auxiliary Transformer (SAT). The SAT is fed from the 230KV Switchyard, which has multiple sources of supply from the 230KV transmission and distribution system. The BSEP Unit 1 and Unit 2 230KV Switchyards are electrically independent of each other and have no crosstie capabilities. The second (i.e., alternate) source of offsite power when recovering from an SBO event is obtained by backfeeding through the Main Transformers from the 230KV Switchyard to the Unit Auxiliary Transformer (UAT). Prior to backfeeding the Main Transformers, the no-load disconnect switch to the Main Generator must be opened. See Figure 2.1-2 of the LRA for a drawing of the SBO recovery path.

c. Unit 2 Switchyard MOD M15 and MOD M16 have been replaced with 230KV gas-filled power circuit breakers (PCBs). PCB M15 and PCB M16 represent the first breaker used for the preferred source of offsite power in the Unit 2 SBO recovery path.

The License Renewal boundary for the Unit I SBO recovery path is currently MOD M 1I and MOD M12. These MODs are scheduled to be replaced with circuit breakers during the spring of 2006. Pending installation of the Unit 1 circuit breakers, the License Renewal boundary for the Unit I SBO recovery path will be at the circuit breakers for the individual offsite feeders.

For both Unit 1 and Unit 2, the License Renewal boundary for the SBO recovery path will be at the first circuit breaker, consistent with ISG-2.

For a detailed description of the SBO recovery path, see the response to RAI 2.1.4.2-1.b above.

NRC RAI 3.1.2.3.1.1-1 LRA Table 3.1.2-1 identifies reduction of fracture toughness due to neutron irradiation embrittlement as AMR entries only for the following RV beltline materials:

a.

RV Shell (Intermediate Beltline Shell)

b.

RV Shell (Beltline Welds)

BSEP 05-0071 Page 9 of 51 In contrast, Tables 4.2-5 and 4.2-6 of the LRA indicate that the following RV beltline components are within the scope of the staff's TLAAs on neutron irradiation embrittlement of RV base metal and weld materials:

a.

RV Lower Shell Plates

b.

RV Lower Intermediate Shell Plates

c.

RV Beltline Vertical (Axial) Welds

d.

RV Beltline Girth (Circumferential) Welds

e.

N-16 A and B Instrumentation Nozzle Forgings The AMRs in LRA Table 3.1.2-1 currently only list AMRs on reduction in fracture toughness/neutron irradiation embrittlement as being applicable to the "RV intermediate beltline shell plates" and the "RV beltline welds."

Part A: Confirm that the term RV "Lower Intermediate Shell" identified in LRATables 4.2-5 and 4.2-6 refers to the same RV shell course as the commodity group term "RV Shell (Intermediate Beltline Shell)" used in LRA Table 3.1.2-1.

Part B: Justify why "reduction of fracture toughness due to neutron irradiation embrittlement" has been omitted as an applicable aging effect in LRA Table 3.1/2-1 for the "Vessel Shell (Lower Shell)" plates when you have identified it and analyzed it as an applicable aging effect for these components in Tables 4.2-5 and 4.2-6 of the LRA. In addition, justify why "reduction of fracture toughness due to neutron irradiation embrittlement" has been omitted as an applicable aging effect In LRA Table 3.1/2-1 for the BSEP-1/2 N-16 instrumentation nozzles when you have identified it and analyzed it as an applicable aging effect for these components in Tables 4.2-5 and 4.2-6 of the LRA. If these are omissions in the application, submit supplemental AMR line entries on "reduction of fracture toughness due to neutron irradiation embrittlement" of the "RV Shell (Lower Shell)" plates and the "N-16 instrumentation nozzles" that, with the exception of the component names, are identical to that provided for "reduction of fracture toughness due to neutron irradiation embrittlement" of the "RV Shell (Intermediate Beltline Shell)" plates.

RAI 3.1.2.3.1.1-1 Response Part A:

The terminology used in LRA Tables 4.2-5 and 4.2-6 is consistent with the submittals BSEP has previously made in relation to Generic Letter 92-01, "Reactor Vessel Structural Integrity." The terminology used in Section 3.1 of the LRA is in the form of "commodity groups."

The "Vessel Shell (Intermediate Beltline Shell)" is a commodity group name derived from NUREG-1801, "Generic Aging Lessons Learned (GALL) Report." It is not meant to describe particular shell courses of the reactor vessel (RV). However, this commodity group does include the following items from Tables 4.2-5 and 4.2-6:

Plates: Lower Shell,

Plates: Lower Intermediate Shell, and

Nozzles: N16A, N16B (i.e., forgings).

BSEP 05-0071 Enclosure I Page 10 of 51 The "Vessel Shell (Beltline Welds)" is another commodity group name derived from GALL.

This commodity group does include the following items from Tables 4.2-5 and 4.2-6:

Welds: Vertical (i.e., GI, G2, Fl, and P2) and

Welds: Girth (i.e., EF and FG).

Part B:

Reduction of fracture toughness due to neutron irradiation embrittlement is an applicable aging effect for all the components in the commodity groups described in Part A.

Note that the AMR line items for cracking due to thermal fatigue in LRA Tables 3.1.2-1, 3.2.2-1, 3.3.2-1, and 3.4.2-1 refer to "Table 1" items 3.1.1-01, 3.2.1-01, 3.3.1-01, and 3.4.1-01, respectively. This "Table 1" item addresses cumulative fatigue damage. Cumulative fatigue damage is addressed topically in Section 4.3 of the BSEP LRA. Cracking due to thermal fatigue is the aging effect/mechanism combination that is addressed by the time-limited aging analyses (TLAAs) when calculating cumulative fatigue damage.

NRC RAI 3.1.2.3.1.2-1 Table 3.1.2-1 of the BSEP-1/2 LRA includes an AMR on loss of preload due to stress relaxation in the nickel-based alloy core plate plugs. To be consistent with the TLAA that is discussed in Section 4.2.8 of the BSEP-1/2 LRA, the staff requests confirmation that the AMR on loss of preload due to stress relaxation in the nickel-based alloy core plate plugs is applicable to only the spring-loaded core plate plugs at BSEP-2, and that the core plate plugs at BSEP-1 are fabricated from stainless steel and involve a welded design.

RAI 3.1.2.3.1.2-1 Response The Unit 2 plug is constructed from stainless steel for the latch, body, shaft, and pin. The spring for the Unit 2 plug is fabricated from a nickel-based alloy.

The nickel-based alloy material associated with the core plate plugs in Table 3.1.2-1 of the LRA refers to the Alloy X-750 spring that provides preload to the core plate plug. This mechanical core plate plug design is applicable to BSEP Unit 2 only.

BSEP Unit 1 does not have the mechanical plugs, but has welded plugs fabricated from stainless steel.

NRC RAI 3.1.2.3.1.2-2 Table 3.1.2-1 of the BSEP-1/2 LRA includes an AMR on cracking of the low alloy steel RV drain line penetrations. In this AMR line item, CP&L identified that the cracking was due to cyclical loading. CP&L did not identify that stress corrosion cracking (SCC) or intergranular stress corrosion cracking (IGSCC) were applicable aging mechanisms that could potentially induce

BSEP 05-0071 Page 11 of 51 cracking in the low alloy steel RV drain line penetrations. Industry experience has demonstrated the SCC and/or IGSCC are concerns for nickel-based alloy weld filler metals. The staff is concerned that cracking due to SCC or IGSCC could be an aging effect requiring management (AERM) for the RV drain line penetrations if the drain lines are joined to the RVs using nickel-based alloy weld filler metals. Confirm whether or not the structural welds for the low alloy steel RV drain line penetrations are fabricated from nickel-based alloy weld filler metals, and if so, provide your basis for concluding that cracking due to SCC or IGSCC is not an AERM for these weld filler metal materials. If the low alloy steel RV drains lines are joined to the RVs using nickel-based alloy weld filler metals and cracking due to SCC or IGSCC is determined to be an AERM for these materials, supplement your LRA to include an AMR on cracking of these components as a result of SCC/IGSCC and identify in the AMR which AMP will be used to monitor for these aging mechanisms. If cracking due to SCC/IGSCC is an AERM for the RV drain line structural welds and is within the scope of an NRC-approved BWRVIP report, identify which NRC-approved BWRVIP Topical Reports is applicable to the assessment of this AERM.

Otherwise, clarify how the AMP credited with aging management will be capable of managing SCC or IGSCC in the structural welds for the RV drain lines during the periods of extended operation for BSEP-1/2.

RAI 3.1.2.3.1.2-2 Response Nickel-based alloys were not used in the fabrication of the drain nozzle. The low-alloy steel nozzle was joined to the low-alloy steel reactor vessel using low-alloy steel weld material.

Therefore, cracking due to SCC, including IGSCC, is not an applicable aging effect.

NRC RAI 3.1.2.3.3-1 Table 3.1.2-1 of the BSEP-1/2 LRA includes an AMR on nozzle safe end (Unit 2 Feedwater),

piping and fittings (Main Steam, Feedwater, and Vessel head Vent ) that are fabricated from carbon steels but connected to stainless steel or nickel alloy components. In the AMR line items, CP&L identified that the cracking was due to cyclical loading. CP&L did not identify that stress corrosion cracking (SCC) or intergranular stress corrosion cracking (IGSCC) are applicable aging mechanisms in these components where there are stainless steel and nickel-based alloy welds. Industry experience has demonstrated that SCC and/or IGSCC are concerns for these weld materials. Confirm whether or not the structural welds for these components are fabricated from stainless steel or nickel-based alloy weld filler metals, and if so, provide your basis for concluding that cracking due to SCC or IGSCC is not an aging effect requiring management (AERM) for these weld filler metal materials.

If cracking due to SCC/IGSCC is an AERM for these components and is within the scope of an NRC-approved BWRVIP report or reports, identify which NRC-approved BWRVIP Topical Report(s) is (are) applicable to the assessment of this AERM., clarify how the AMP credited with aging management will be capable of managing SCC or IGSCC in these components during the periods of extended operation for BSEP-1/2.

BSEP 05-007 1 Page 12 of 51 RAI 3.1.2.3.3-1 Response The BSEP LRA did identify cracking due to SCC (i.e., including IGSCC) as an applicable aging effect for stainless steel and nickel-based alloy components and welds associated with the reactor vessel.

Unit 2 Feedwater Nozzle Safe End The BSEP Feedwater Nozzles are fabricated from carbon steel and are partially clad with stainless steel. This is described in the BSEP LRA with plant-specific note 120 which states:

This component is partially clad with stainless steel.

Cracking due to SCC was identified as an applicable aging effect for the cladding on the Feedwater Nozzles. Refer to Page 3.1-25.

The Unit 2 Feedwater Nozzle safe end is fabricated from carbon steel. The Unit 2 Feedwater Nozzle is joined to the Unit 2 Feedwater Nozzle safe end with a carbon steel weld. Cracking due to SCC is not an applicable aging effect for the carbon steel weld.

Main Steam Piping and Fittings The Main Steam piping is fabricated from carbon steel. As described in plant-specific note 116:

The cast austenitic stainless steel material is only applicable to the Main Steam Flow Limiters.

Cracking due to SCC was identified as an applicable aging effect for the Main Steam Flow Limiters. The weld material is evaluated as part of the "Main Steam Piping and Fittings" commodity group that includes the Main Steam Flow Limiters.

Feedwater Piping and Fittings The Feedwater piping is fabricated from carbon steel. As described in plant-specific note 119:

The stainless steel material is only applicable to thermowells installed in the feedwater piping.

Cracking due to SCC was identified as an applicable aging effect for the Feedwater thermowells.

The weld material is evaluated as part of the "Feedwater Piping and Fittings" commodity group that includes the Feedwater thermowells.

Head Vent Piping and Fittings The Head Vent Nozzle is part of the commodity group "Top Head Enclosure (Nozzles (Vent, Top Head Spray or Reactor Core Isolation Cooling [RCIC], and Spare))" shown on page 3.1-18 of the

BSEP 05-0071 Enclosure I Page 13 of 51 BSEP LRA. The Head Vent Nozzle is fabricated from low-alloy steel. The Head Vent piping is fabricated from carbon steel as shown on page 3.1-73 of the BSEP LRA. The Head Vent Nozzle is joined to the Head Vent piping with a carbon steel weld. Cracking due to SCC is not an applicable aging effect for the carbon steel weld.

NRC RAI 3.1.2.3.3-2 Table 3.1.2-1 of the BSEP-1/2 LRA includes an AMR on nozzle safe end (Unit 1 Feedwater) that were a replacement of an original safe end that cracked. In the footnote, CP&L stated that, "previously there had been a gap between the nozzle and its thermal sleeve that appeared to be related to feedwater sparger cracking." Please identify if Unit 2's safe end is still of the original design with a gap that may prone to promote cracking. Identify if additional inspection, in addition to Section XI ISI requirements, may be needed.

RAI 3.1.2.3.3-2 Response The Unit 2 Feedwater nozzle safe end is still of the original interference fit design. The Feedwater spargers are part of the commodity group "Reactor Vessel Internals (Boiling Water Reactor - Non-safety Related) (Feedwater Spargers)" shown on page 3.1-69 of the LRA.

Cracking due to SCC is managed by a combination of the Water Chemistry Program and Reactor Vessel and Internals Structural Integrity Program. The Reactor Vessel and Internals Structural Integrity Program includes the enhanced inspections associated with NUREG-0619, "BWR Feedwater Nozzle and Control Rod Drive Return Line Nozzle Cracking." See Section B.2.28 of the BSEP LRA.

NRC RAI 3.1.2.3.3-3 Tables 3.1.2-1, 3.1.2-2, 3.1.2-3, 3.1.2-4, 3.1.2-5 and 3.3.2-1 of the BSEP-1/2 LRA include class 1 small bore piping and fittings. For the associated aging effects, CP&L identified Section XI Inservice Inspection (ISI) and Water Chemistry as the AMPs. However, the applicant did not identify any of these items for a one time inspection. Please provide technical bases that no additional inspection is needed, other than those required by Section XI, for the periods of extended operation for BSEP-1/2.

RAI 3.1.2.3.3-3 Response The Class 1 small bore piping and fittings have been included in the One-Time Inspection Program. Audit Question B.2.15-1 has previously addressed this issue, and the response is contained in BSEP letter to the NRC (Serial: BSEP 05-004 1), dated March 14, 2005 (Accession Number ML050810493). The response states in part:

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.

BSEP 05-0071 Page 14 of 51 NRC RAT 3.1.2.3.3-4 Table 3.1.2-4 of the BSEP-1/2 LRA includes CRD gearbox coolers made with carbon steel that are exposed to a lube oil environment. In the AMR line items, CP&L did not identify any aging mechanisms. Previous licensee renewal review and industry experience have demonstrated that loss of material and cracking, and reduction of heat transfer for coolers, are applicable aging effects for carbon steel components in a lube oil environment. Clarify if these aging effects are applicable to the carbon steel components in the CRDM gear box coolers that are exposed to lube oil. If any of these aging effects are applicable AERMs, propose aging management activities or programs to manage the applicable aging effects.

RAI 3.1.2.3.3-4 Response The BSEP AMR methodology concluded that carbon steel in a lube oil environment does not lead to loss of material or cracking in the absence of water contamination. Water contamination of lube oil systems is not assumed unless indicated by operating experience or design review.

Water pooling/separation in lube oil are only assumed if (1) potential for water contamination exists and (2) system design/physical arrangement is conducive to water separation and pooling (i.e., low points, stagnant flow, etc). A design review concluded that these conditions are not applicable to the subject Control Rod Drive (CRD) Hydraulic System components. Plant-specific operating experience was reviewed and determined that water contamination of lube oil has not been detected. Therefore, the lube oil environment is benign for carbon steel.

NRC RAI 3.6.2.3-1 With regards to BSEP AMP B.2.31, "Phase Bus Aging Management Program," provide the following:

a. Describe what portions of the iso-phase bus, non-segregated phase buses (4.16KV and 480V) within the scope of License Renewal are included in the scope of this AMP.

b. Under Element 3, you have stated that a sample of accessible bolted connections will be checked for adequate torque. Bolted connections covered with heat shrink tape, sleeving, insulation boots, etc., are inaccessible and are not covered by this activity. This program will also inspect the bus enclosure for cracks, corrosion, foreign debris, excessive dust build up, and evidence of water intrusion.

1. Clarify if this inspection will cover inside of the bus enclosure for foreign debris, excessive dust build up, and evidence of water intrusion. Does plant specific structure monitoring program inspect the external of the bus ducts for corrosion and bus duct seals for cracking?

BSEP 05-007 1 Page 15 of 51

2. Vendors and bolting practices do not typically recommend to re-torque of bolted connections unless the joint requires service or the bolted connections are clearly loose. The torque required to turn the fastener in the tightening direction (restart torque) is not a good indication of the preload once the fastener is in service. Due to relaxation of the parts of the joint, the final loads are likely to be lower than the installed loads. Provide a technical justification detailing how retorquing of bolted connections is a good indicator of the preload once the fastener is in service. The Acceptance Criteria (Element 6) needs to be modified accordingly.

3. You have stated that bolted connections covered with heat shrink tape, sleeving, insulating boots, etc., are inaccessible and are not covered by this activity. Provide another method for detecting bolted connection loosening due thermal cycling or provide a technical justification of why inaccessible bolted connections are not subject to thermal cycling.

RAI 3.6.2.3-1 Response

a.

A Phase bus is an assembly of rigid conductors (i.e., bus) within a metal enclosure that serves as a common electrical connection between two or more elements (i.e., electrical equipment such as switchgear and transformers) of an electrical circuit. The non-segregated 4.16KV and 480V phase bus is constructed with all phase conductors in a common enclosure without barriers (i.e., only air space) between the phases. The BSEP AMP includes only those portions of the phase bus between the connected end devices that are not part of an active component such as a switchgear load center, motor control center or transformer. The phase buses within the scope of this BSEP AMP are identified below:

Iso-Phase Bus Connects the Main PowerTransformers to the UAT during SBO backfeeding Non-Segregated 4.16KV Phase Bus Connects SAT 1 to 4.16KV Buses IC and ID Connects SAT 2 to 4.16KV Buses 2C and 2D Connects UAT 1 to 4.16KV Buses IC and ID Connects UAT 2 to 4.16KV Buses 2C and 2D Crossties between Emergency Switchgear El, E2, E3, and E4 Non-Segregated 480V Phase Bus Crossties between Unit Substations E5, E6, E7, and E8

b. 1 The intent of this electrical AMP is to preserve the electrical continuity function of the phase bus. This inspection activity will cover the inside of the bus enclosure which houses the rigid bus conductors. This activity will inspect the inside of the bus enclosure for foreign debris, excessive dust build up, and evidence of water intrusion.

The external surfaces of the phase bus housing will be inspected by the Structures Monitoring Program under the electrical enclosures commodity group as shown in Section B.2.23 of the LRA. There are no seals on the phase bus housing except on the

BSEP 05-0071 Page 16 of 51 inspection ports, which are gasketed. The gaskets are replaced on an as-needed basis during routine Preventive Maintenance (PM) Program activities.

b.2 The proposed activity to retorque bolted connections, even on a sample basis, is contrary to vendor recommendations and good bolting practices discussed in Electric Power Research Institute (EPRI) Technical Report 1003471, December 2002, and EPRI Technical Report 104213, December 1995. In lieu of this, the contact resistance across accessible bolted connections at sample locations will be measured using a low range ohmmeter. The Acceptance Criteria in Element 6 will be modified accordingly.

b.3 A visual inspection of the inaccessible bolted connection is an appropriate technique for determining the condition of the joint. Inaccessible bolted connections will be inspected for signs of embrittlement, cracking, melting, swelling, or discoloration, which may indicate overheating or aging degradation.

NRC RAI 3.6.2.3-2 Address AMR for metals and inorganic materials (such as cable fillers, epoxies, potting compounds, connector pins, plugs, and facial grommets) associated with non-EQ electrical/I&C penetration assemblies.

RAI 3.6.2.3-2 Response Electrical penetration assemblies are used to pass electrical circuits through the Containment Drywell while maintaining Drywell integrity. The intent of the electrical AMR of electrical penetration assemblies is to preserve the electrical continuity function of the penetration assemblies. The focus of this review is the interaction between the organic insulating materials of the assemblies and their operating environment. The organic insulating materials comprise the penetration primary insulation system of the assemblies. In addition to organic insulating materials, there are other materials (i.e., metals and inorganic materials) used in the construction of the penetration assembly. These include cable fillers, epoxies, potting compounds, connector pins, plugs, and facial grommets. Consistent with the Department of Energy (DOE)/Sandia Aging Management Guideline (SAND 96-0344) these items have no significant effect on the normal aging process of the primary insulation system and do not adversely affect the electrical continuity function of the penetration assemblies. Therefore, no AMR of these materials is warranted. The civil/structural pressure boundary function of the penetration is tested by the Appendix J Program as shown in Table 3.5.2-1 of the LRA.

NRC RAI 3.6.2.3-3 Various airborne materials such as dust, salt and industrial effluent can contaminate insulator surfaces. A large buildup of contamination enables the conductor voltage to track along the surface more easily and can lead to insulator flash over. Surface contamination can be a problem in areas where there are greater concentration of airborne particles such as near facilities that

BSEP 05-0071 Page 17 of 51 discharge soot or near the sea coast where salt spray is prevalent. Industry operating experience identified the potential of loss of offsite power due to salt contamination of switchyard insulators at other plants beside BSEP. On March 17, 1993, Crystal River Unit 3 experienced a loss of the 230 kV switchyard (normal off-site power to safety-related busses) when a light rain caused arcing across salt-laden 230 kV insulators and opened breakers in switchyard. Since 1982, Pilgrim station has also experienced several loss of offsite power events when heavy ocean storms deposited salt on the 345 kV switchyard causing the insulator to arc to ground. In light of these industry operating experiences, provide an AMP to manage the aging effects of insulator or provide a justification of why an AMP is not necessary.

RAI 3.6.2.3-3 Response Surface contamination on BSEP high-voltage insulators is an applicable aging mechanism that requires management. A silicon-based coating has been applied to the 230KV porcelain insulators to prevent the buildup of surface contamination. As part of the PM Program AMP, the silicon-based coating on the switchyard insulators will be tested. This test consists of the application of a water mist to verify that water beads are present. An initial performance interval of once every refueling outage will be established for this inspection. Should test results warrant an additional coating of silicon, the first inspection following reapplication may be extended.

Subsequent inspections after the initial inspection will occur every refueling outage. This test will become part of the PM Program described in Section A.1.1.32 of the LRA. The program description for the PM Program described in Section B.2.30 of the LRA is amended by this response as follows:

System PM Program Activity 230KV Switchyard System Inspect high-voltage insulators for water beading on silicone coating and for age related degradation.

-2 I

NRC RAI 3.6.2.3-4 Loss of material due to the corrosion of connections due to surface oxidation is an aging effect for the switchyard bus, switchyard bus connections and transmission conductor connections.

Explain why loss of material due to corrosion is not an applicable aging effect for switchyard bus, switchyard bus connections and transmission conductor connections.

RAI 3.6.2.3-4 Response Loss of material due to the corrosion of connections due to surface oxidation is an applicable aging mechanism but is not significant enough to cause a loss of intended function. The components involved in switchyard connections are constructed from cast aluminum, galvanized steel and stainless steel. The switchyard bus is constructed of 5-inch, schedule 80, aluminum pipe. No organic materials are involved. Connections to the switchyard bus are welded.

Conductor connections are generally of the compression bolted category. Components in the switchyard are exposed to precipitation. The components in the switchyard do not experience

BSEP 05-0071 Page 18 of 51 any appreciable aging effects in this environment, except for minor oxidation, which does not impact the ability of the switchyard bus to perform its intended function.

At BSEP, switchyard connection surfaces are coated with an anti-oxidant compound (i.e., a grease-type sealant) prior to tightening the connection to prevent the formation of oxides on the metal surface and to prevent moisture from entering the connection thus reducing the chances of corrosion. Based on operating experience, this method of installation has been shown to provide a corrosion resistant low electrical resistance connection. Therefore, it is concluded that general corrosion resulting in the oxidation of switchyard connection surface metals is not an AERM at BSEP.

NRC RAI 3.6.2.3-5 The most prevalent mechanism contributing to loss of high voltage transmission conductor strength is corrosion which includes corrosion of steel core and aluminum strand pitting.

Provide a technical basis for why the loss of conductor strength due to corrosion of ACSR transmission conductor is a slow process and therefore is not significant.

RAI 3.6.2.3-5 Response Loss of transmission conductor strength due to corrosion is an applicable aging effect, but ample design margin ensures that it is not significant enough to cause a loss of intended function.

BSEP transmission conductors are Type ACSR (i.e., aluminum conductor steel reinforced). They are constructed of strand aluminum conductors wound around a steel core. No organic materials are involved. The most prevalent mechanism contributing to loss of conductor strength of an ACSR transmission conductor is corrosion, which includes corrosion of the steel core and aluminum strand pitting. For ACSR transmission conductors, degradation begins as a loss of zinc from the galvanized steel core wires. Corrosion rates depend largely on air quality, which includes suspended particle chemistry, SO2 concentration in air, precipitation, fog chemistry, and meteorological conditions. Corrosion of ACSR transmission conductors is a very slow process that is even slower for rural areas with generally fewer suspended particles and lower SO2 concentrations in the air than urban areas. BSEP is located in a rural area where airborne particle concentrations are comparatively low. Consequently, this is not considered a significant contributor to this aging mechanism.

There is a set percentage of composite conductor strength established at which a transmission conductor is replaced. The National Electrical Safety Code (NESC) requires that tension on installed conductors be a maximum of 60% of the ultimate conductor strength. The NESC also sets the maximum tension a conductor must be designed to withstand under heavy load requirements, which includes consideration of ice, wind, and temperature. Tests performed by Ontario Hydroelectric showed a 30% loss of composite conductor strength of an 80-year-old transmission conductor due to corrosion. Assuming a 30% loss of strength, there would still be significant margin between what is required by the NESC and actual conductor strength.

BSEP 05-0071 Enclosure I Page 19 of 51 These requirements were reviewed concerning the specific transmission conductors used at BSEP. BSEP is in the medium loading zone; therefore, the Ontario Hydroelectric heavy loading zone study is conservative. The BSEP transmission conductors with the smallest ultimate strength margin, i.e., 1272 MCM ACSR, will be used as an illustration. The ultimate strength of 1272 MCM ACSR is 34,100 lbs and the maximum heavy load tension of 1272 MCM ACSR is 3,000 lbs. The margin between the heavy load tension and the ultimate strength is 31,100 lbs.;

therefore, there is a 91% ultimate strength margin (i.e., 31,100/34,100). The Ontario Hydroelectric study showed a 30% loss of composite conductor strength in an 80-year-old conductor. In the case of the 1272 MCM ACSR transmission conductors, a 30% loss of ultimate strength would mean that there would still be a 61% ultimate strength margin between what is required by the NESC and the actual conductor strength in an 80-year old conductor.

The BSEP transmission conductors within the scope of License Renewal are short spans located entirely within the switchyard area. The spans are approximately 287 feet in length. Therefore, the tension exerted on these conductors is less than would be experienced in typical applications, which could be up to 1000 feet in length.

The foregoing discussion illustrates that there is ample design margin in the transmission conductors at BSEP. Based on the conservatism in the ultimate strength margin, it is concluded that loss of conductor strength is not an AERM at BSEP.

NRC RAI 3.6.2.3-6 Torque relaxation for bolted connections is a concern for switchyard bus connections and transmission conductor connections. An electrical connection must be designed to remain tight and maintain good conductivity through a large temperature range. Meeting this design requirement is difficult if the material specified for the bolt and the conductor are different and have different rates of thermal expansion. For example, copper or aluminum bus materials expand faster than most bolting materials. If thermal stress is added to stresses inherent at assembly, the joint members or fasteners can yield. If plastic deformation occurs during thermal loading (i.e., heat up) when the connections cools, the joint will be loose. Provide a discussion why torque relaxation for bolted connections of switchyard bus and transmission conductor connections is not a concern.

RAI 3.6.2.3-6 Response The only bolted connections in the switchyard are used in transmission conductor connections to switchyard components such as bus, transformers, and breakers. The switchyard bus is all welded construction. The only bolted connections associated with the switchyard bus are for the connections to the transmissions conductors. BSEP bolting hardware was selected to be compatible with the connector/conductor coefficient of thermal expansion. This ensures that the contact pressure of the bolt and washer combination used in the connector is maintained to the initial vendor specified torque value. BSEP design incorporates the use of stainless steel "Belleville" washers on all bolted electrical connections to compensate for temperature changes, maintain the proper torque and prevent loosening. This method of assembly is consistent with

BSEP 05-007 1 Page 20 of 51 the good bolting practices recommended in EPRI Technical Report 1003471, "Bolted Joint Maintenance and Applications Guide," December 2002. A review of site operating experience revealed no switchyard bolted connection failures attributed to aging. This confirms the proper design and installation of BSEP switchyard bolted connections and demonstrates their reliability.

Based on BSEP design configuration and a review of site operating experience, it is concluded that torque relaxation of bolted connections on transmission conductors is not an aging effect requiring management.

NRC RAI 4.2.1-1 In the License Renewal Application (LRA) for the Brunswick Steam Electric Station, Units 1 and 2 (BSEP-1/2), Carolina Power and Light Company (CP&L) establishes that the number of effective full power years (EFPY) in the projected 60-year design basis is 54 EFPY. Clarify how the current historical capacity factors for the current operating terms and the projected capacity factors for the periods of extended operation for BSEP-1/2 establish 54 EFPY as a reasonable conservative estimate of the capacity factor.

RAI 4.2.1-1 Response Fluence projections were prepared for Extended Power Uprate (EPU) based upon flux determined by an updated neutron transport calculation. The projected end-of-life EFPY increased from 32 to 50 on Unit 1 and from 32 to 48 on Unit 2 based upon an EPU capacity factor of 97% and 60-year life.

For License Renewal analyses based upon neutron fluence, a 54 EFPY value was selected for conservatism and consistency with other LR Applications.

NRC RAI B.2.28-1

[Scope of Program] Program Attribute: In Table 3.1.2-1 of the LRA for BSEP-1/2, CP&L credits the Reactor Vessel and Internals Structural Integrity Program (henceforth in the RAIs for this aging management program abbreviated as the RV&ISIP) with the management of aging effects requiring management (henceforth referred to as AERMs in the RAIs for this AMP) for the following RV and RV internal components:

vessel shell attachment welds fuel support and CRD assembly feedwater nozzles and their thermal components, including orifice fuel sleeves support and CRD housings vessel instrumentation penetrations flux monitor dry tubes, including standby liquid control penetrations those for the source range monitors, flux monitor penetrations intermediate range monitors,

BSEP 05-0071 Page 21 of 51 RV drain line penetration low pressure core spray line thermal sleeves core shroud shell (including upper, middle, and lower shell components) core shroud access hole covers core shroud repair hardware core plates and their bolts core spray line nozzle thermal sleeve jet pump instrument penetrations jet pump assembly components, including thermal sleeves, inlet headers, riser brace arms, hold down beams, inlet elbows, mixing assemblies, diffusers, castings, sensing lines, and fastener components (hold own beam keeper, lock plate, and bolts) feedwater spargers (non-safety)

RV surveillance capsule holder (non-safety) core plate plugs (welded plugs at BSEP-1 and spring-loaded plugs at BSEP-2) core shroud support structure top guide core spray line headers, nozzles, spargers, and spray-rings steam dryers (non-safety) shroud head and separators (non-safety)

In addition, Table B.2.28-1 on the following page provides a list of Boiling Water Reactor Vessel and Internals Project (BWRVIP) Topical Reports that are applicable to the RV and RV internal components at BSEP-1/2. CP&L's [Scope of Program] program attribute for the RV&ISIP does not identify which RV and RV internal components are within the scope of the RV&ISIP or which additional BWRVIP topical report guidelines (i.e., in addition to BWRVIP-74-A and BWRVIP-94) are within the scope of the RV&ISIP relative to the management of AERMs in these components. Provide the following clarifications with respect to the [Scope of Program]

program attribute for the RV&ISIP:

a.

Confirm that the RV and RV internal components provided in the bulleted list are within the scope of the RV&ISIP. Identify any additional RV or RV internal components that are within the scope of the RV&ISIP that have not been included in the list of components for this RAI.

b.

Identify all BWRVIP and Boiling Water Reactor Owners Group (BWROG) Topical Report Guidelines (i.e., in addition to Topical Report Nos. BWRVIP-74-A and BWRIP-94) that are within the scope of RV&ISIP and clarify which RV and/or RV internals components are within the scope of the applicable BWRVIP/BWROG guidelines. For those BWRVIP Topical Reports in Table B.2.28-1 that are currently under the NRC's review and are pending NRC approval, discuss the process that will be taken by CP&L to endorse the report as being applicable to BSEP-1/2 once the reports have been approved and endorsed by the NRC.

c.

The [Scope of Program] Program Attribute, in part, states that CP&L will implement the RV&ISIP and the applicable BWRVIP Guidelines within the scope of the AMP in accordance with BWRVIP-94. Section 3.5 of BWRVIP-94 includes the following

BSEP 05-0071 Page 22 of 51 guidance on implementing exceptions or deviations to BWRVIP Guideline recommendations:

"Each utility will inform the NRC of any decision to not fully implement a BWRVIP guideline approved by the NRC staff within 45 days of the report approval."

"The NRC should be notified if changes are made to the vessel and internals program that affect implementation of the BWRVIP guidelines."

"Flaw evaluations that deviate from guidance in BWRVIP reports shall be submitted to the NRC for approval."

Confirm that these BWRVIP-94 recommendations are within the scope of the RV&ISIP and the scope of your responses to Applicant Action Item (AAI) No. 1 on Topical Report Numbers.

BWRVIP-74-A, -18, -25, -26, -27, -38, -41, -47, -48, and -49.

Table B.2.28-1 Component Reference SER Date SER Accession Nos.

Reactor Vessel (RV)

BWRVIP-74-A 10/18/01 ML012920549 Components Core Shroud Support and BWRVIP-38 03/01/01 ML010600211 Attachments Core Shroud BWRVIP-76 Under Review N/A Nozzle Safe Ends and BWRVIP-75 09/15/00 ML003751105 P iping Core Support Plate BWRVIP-25 12/07/00 ML003775989 Core AP/SLC Line and BVRVIP-27 12/20/99 ML993630179 Core Spray, Jet Pump Riser Brace, and Other BWRVIP-48 01/17/01 ML010180493 Attachments Core Spray Lines and BWRVIP-18 12/07/00 MLO03775973 Spargers Top Guide BWRVIP-26 12/07/00 ML003776110 Jet Pump Assemblies BWRVIP-4 1 05/01/01 MLO 11310322 CRDH Stub Tubes and Guide Tubes and ICM BWRVIP47 12/07/00 ML003775765 Housing Guide Tubes and Penetrations Instrument Penetrations BWRVIP-49 03/13/02 Fiche A9153/241-253

BSEP 05-0071 Page 23 of 51 RAI B.2.28-1 Response

a.

The bulleted list provided is correct with the following exceptions:

The list should include: "Penetrations (CRD Stub Tubes)" and "Instrumentation (Incore Neutron Flux Monitor Guide Tubes)."

The jet pump sensing lines, which are internal to the reactor vessel, are within the scope of License Renewal but do not require an aging management program. Section 3.1.2.2.4.2 of the BSEP LRA states:

The jet pump sensing lines were evaluated for flow induced vibration as part of the Extended Power Uprate (EPU). This evaluation determined that the sensing line natural frequency of interest is well separated from vane passing frequency of the recirculation pumps at EPU conditions. The failure of a sensing line at any location would be detectable during jet pump surveillance that is done at least daily. Failure of a sensing line does not affect the pressure measurement taken for post-accident water level monitoring. If one or more jet pumps are inoperable, the plant must be brought to Mode 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. Therefore, no aging management program is required.

BWRVIP-41, "BWR Jet Pump Assembly Inspection and Flaw Evaluation Guidelines,"

Section 2.3.12.7, concludes that inspection of sensing lines is essentially occurring continuously during plant operation by the monitoring of jet pump flow.

The NRC found this position acceptable in NUREG-1796, "Safety Evaluation Report Related to the License Renewal of the Dresden Nuclear Power Station, Units 2 and 3 and Quad Cities Nuclear Power Station, Units 1 and 2," Accession Numbers ML043060582 and ML043060584. Section 3.1.2.2.4(2) on page 3-96 states:

The staff finds the applicant's decision of not including the jet pump sensing line within the scope of license renewal acceptable because plant operation essentially provides for continuous monitoring of the sensing line integrity and, if a line fails, Plant Technical Specifications require either a plant shut down or safety assessment to justify continued operation.

b.

Part 1 - Identify all BWRVIP guidelines that are within the scope of RV&ISIP.

The BWRVIP guidelines in the Reactor Vessel and Internals Structural Integrity Program other than BWRVIP-74-A are:

BWRVIP-18, BWRVIP-25, BWRVIP-26, BWRVIP-27, BWRVIP-38, BWRVIP-41, BWRVIP-47, BWRVIP-48, BWRVIP-49, and BWRVIP-76.

BSEP 05-0071 Enclosure I Page 24 of 51 These guidelines are employed using the program implementation guidance of BWRVIP-94. As noted in Section B.2.28 of the BSEP LRA, BWRVIP-42 is not applicable. BWRVIP-75, "Technical Basis for Revisions to Generic Letter 88-01 Inspection Schedules," is used in the basis for the BSEP BWR Stress Corrosion Cracking Program. This program is described in Section B.2.4 of the BSEP LRA. The BWRVIP guidelines related to water chemistry are discussed in Section B.2.2 of the BSEP LRA.

The program will be implemented based on the best available guidance from the BWRVIP.

Part 2 - Clarify which RV and/or RV internals components are within the scope of the applicable BWRVIP/BWROG guidelines.

The appropriate individual BWRVIP guidelines that are part of the Reactor Vessel and Internals Structural Integrity Program are applied to the components discussed in the response to Part A of this RAI.

Part 3 - For those BWRVIP Topical Reports in Table B.2.28-1 that are currently under the NRC's review and are pending NRC approval, discuss the process that will be taken by CP&L to endorse the report as being applicable to BSEP-1/2 once the reports have been approved and endorsed by the NRC.

The governing BSEP procedure for the Reactor Vessel and Internals Structural Integrity Program states:

Any required program changes (new or revised guidelines) should be incorporated into the program within 60 days of identification.

c.

The governing BSEP procedure for the Reactor Vessel and Internals Structural Integrity Program incorporates the recommendations from the best available guidance from the BWRVIP. These recommendations are within the scope of the BSEP responses to AAI No. 1 on Topical Report Numbers: BWRVIP-74-A, -18, -25, -26, -27, -38, -41, -47, -48, and -49.

NRC RAI B.2.28-2 Preventative Actions Program Attribute: The program attribute identifies that the control of water chemistry quality (maintaining high water quality) is used to reduce the susceptibility of the RV and RV internal components to stress corrosion cracking (including intergranular stress corrosion cracking) and is accomplished through implementation of the latest BWRVIP Guidelines on water chemistry control. Confirm that control of water chemistry quality is also used to reduce the susceptibility of the RV and RV internal components to loss of material by general corrosion, pitting corrosion, and crevice corrosion. Identify (reference), by title and report number, which water chemistry guidelines will be used for mitigation of these corrosion-induced aging mechanisms in the RV and RV internal components. The scope of this RAI

BSEP 05-0071 Page 25 of 51 response is also applicable to the applicant's response to Applicant Action Item (AAI) No. 6 on Topical Report BWRVIP-74-A.

RAI B.2.28-2 Response The BSEP Water Chemistry Program is used to reduce the susceptibility of the RV and RV internal components to loss of material by general corrosion, pitting corrosion, and crevice corrosion. Section B.2.2 of the LRA states:

The main objective of the Water Chemistry Program is to minimize loss of material, cracking, and flow blockage.

Regarding Boiling Water Reactor (BWR) water chemistry control, the response to AAI No. 6 on Topical Report BWRVIP-74-A states:

The BSEP BWR Stress Corrosion Cracking Program includes water chemistry control as a preventive measure. The Water Chemistry Program is in accordance with the latest guidelines of the BWRVIP, this helps ensure the long-term integrity and safe operation of the Reactor Vessel and Internals components.

In addition Section B.2.2 also states:

The BSEP Water Chemistry Program is based on the latest version of the BWRVIP Water Chemistry Guidelines (currently BWRVIP-79 EPRI Report TR-103515-R2, which is the 2000 Revision of "BWR Water Chemistry Guidelines"). EPRI incorporates new information to develop proactive plant-specific water chemistry programs to minimize intergranular stress corrosion cracking (IGSCC). EPRI periodically updates the water chemistry guidelines, as new information becomes available. The BSEP Water Chemistry Program will be updated as revisions to the guidelines are released.

NRC RAI B.2.28-3 Detection of Aging Effects and Monitoring and Trendinr Program Attributes: The program attributes states that CP&L will inspect the RV and RV internal components using a combination of visual, surface, and ultrasonic examination techniques, and that the examination methods and frequencies will be consistent with applicable BWRVIP Guideline Reports and, for feedwater nozzles, the BWROG "Alternate BWR Feedwater Nozzle Inspection" Report. The RV&ISIP also states that CP&L will conduct augmented inspections of the BSEP-1/2 top guides in accordance with the recommendations of BWRVIP-26 and that the inspections of the top guides will be similar to the enhanced inspections that are proposed for the control rod drive housing (CRDH) guide tubes. CP&L's program for the CRDH guide tubes calls for an enhanced VT-1 inspection of a 10% sample of the CRDH guide tubes within 12 years, with half of these inspections (5%) being completed within six years. Confirm that the augmented inspections of the top guides will be performed in accordance with Topical Report BWRVIP-26, as approved by the staff in its FSER of December 7, 2000, and that the sample size attributes on the enhanced

BSEP 05-0071 Page 26 of 51 VT-1 examinations of the BSEP-1/2 top guide structures are in terms of percent of exposed area for examination. Clarify what the sample size and inspection frequency will be for the enhanced VT-1 examinations of the top guides at BSEP-1/2. Clarify whether the selection of top guide locations for inspection will be based on those that are projected to have the highest projected neutron fluence values (E 2 1.0 MeV) at the expiration of the periods of extended operation, or if another basis is being used to top guide location selection, clarify what it is. If any of the information in your response to this question is proprietary in content, identify which data or information is considered to proprietary in content, and, pursuant to the withholding criteria of 10 CFR 2.390, submit a proprietary affidavit on the data or information that is considered to be proprietary in content. The response to this RAI is also applicable to the CP&L's response to AAI No.4 of BWRVIP-26, as defined in Table 4 of the RV&ISIP.

RAI B.2.28-3 Response The augmented inspections of the top guide will be in accordance with BWRVIP-26 as approved for use in license renewal by the NRC staff in its Final Safety Evaluation Report (FSER) of December 7, 2000. The inspection technique will either be an enhanced VT-1 or volumetric.

The sample size attributes for the inspections of the BSEP Units 1 and 2 top guide structures will be in terms of percent of exposed susceptible areas above the irradiation assisted stress corrosion cracking threshold for examination. As stated in the response to AAI No. 4 of BWRVIP-26:

The top guide inspections will focus on the high fluence region. These augmented inspections may be modified should BWRVIP 26 be revised in the future.

The sample size will be 10% of the affected susceptible area within 12 years with 5% being completed within 6 years.

NRC RAI B.2.28-4 Detection of Agingi Effects and Monitoring and Trending Program Attributes: In CP&L Serial Letter No. BSEP-00-0069, dated June 23, 2000, CP&L indicated that it inspects 25 percent of the BSEP core shroud repair clamps (bracket assemblies) during scheduled refueling outages for the units. This differs from the recommended sample size for repair assemblies in Proprietary Topical Report BWRVIP-76 (i.e., Proprietary EPRI Topical Report No.

TR-1 14232, "BWR Vessel and Internals Project, BWR Core Shroud Inspection and Flaw Evaluation Guidelines" [BWRVIP-76].). State whether CP&L is committed to continue its practice of performing augmented inspections of the core shroud repair clamps (bracket assemblies) in each unit during the scheduled refueling outages in the periods of extended operation, and if so, identify what type of inspection methods, sample size and inspection frequency will be used for the augmented inspection of the core shroud repair clamps during the periods of extended operation for BSEP-1/2. If the inspection method(s), sample sizes, or inspection frequency will be different from the inspection method, sample size, or inspection frequency in BWRVIP-76, justify how the alternatives to BWRVIP-76 recommendations will continue to provide assurance of the integrity of core shroud repair clamps during the periods of extended operation for BSEP-1/2. If any of the information in your response to this question is

BSEP 05-0071 Page 27 ofS1 proprietary in content, identify which data or information is considered to proprietary in content, and, pursuant to the withholding criteria of 10 CFR 2.390, submit a proprietary affidavit on the data or information that is considered to be proprietary in content.

RAI B.2.28-4 Response BSEP is currently performing inspections of the core shroud repair hardware according to the requirements of BWRVIP-76, i.e., currently 33% of the core shroud repair hardware clamps are being inspected each outage.

NRC RAI B.2.28-5 Detection of Aging Effects and Monitoring and Trending Program Attributes: In Section 4.2.8 of the BSEP-1/2 LRA, CP&L's states that the RV&ISIP will be used to manage loss of preload/stress relaxation in the spring-loaded core plate plugs at BSEP-2. The Detection of Aging Effects and Monitoring and Trending program attributes did not discuss how the RV&ISIP will be used to manage loss of preload/stress relaxation in the spring-loaded core plate plugs.

Discuss how the RV&ISIP will capable of managing loss of preload/stress relaxation in the spring-loaded core plate plugs. In particular, discuss what type of inspection method, inspection qualifications, inspection sample size, and inspection frequency will be used for the examinations of the spring-loaded core plate plugs at BSEP-2. If a particular BWRVIP Guideline Report will be implemented for the examinations of the spring-loaded core plate plugs, reference the report that is applicable to the examinations of the core plate plugs. If any of the information in your response to this question is proprietary in content, identify which data or information is considered to proprietary in content, and, pursuant to the withholding criteria of 10 CFR 2.390, submit a proprietary affidavit on the data or information that is considered to be proprietary in content.

RAI B.2.28-5 Response In the response to RAI 4.2.8-1, Part A, and RAI 4.2.8-2 in BSEP letter to the NRC (Serial: BSEP 05-0050), dated May 4, 2005, BSEP stated that the Reactor Vessel and Internals Structural Integrity Program, discussed in BSEP LRA Section B.2.28, will manage loss of preload due to stress relaxation of the spring-loaded core plate plugs installed in Unit 2 by replacement.

NRC RAI B.2.28-6 Part A and B - on the [Detection of Aging Effects] and [Monitoring and Trending] Program Attributes for the RV&ISIP: In CP&L's response to NRC Audit Question 3.1-2, as given in CP&L Serial Letter No. BSEP 05-0041, dated March 14, 2005, CP&L provided the following clarification of its management strategy for the welded access hole covers (AHCs):

BSEP 05-0071 Page 28 of 51 AQ 3.1-2 Response (a) The American Society of Mechanical Engineers (ASME) Code Section XI inservice inspection (ISI) requirements are captured as part of the Reactor Vessel and Internals Structural Integrity Program. As stated in Section B.2.28 of the LRA:

The Reactor Vessel and Internals Structural Integrity Program is an existing plant-specific program that includes:

Inspection in accordance with the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program and inspection and flaw evaluation in conformance with the guidelines of the BWR Owners Group, Boiling Water Reactor Vessel and Internals (BWRVIP) documents.

(b) The procedures that implement the Reactor Vessel and Internals Structural Integrity Program include enhanced inspections of the access hole covers. Specifically, the inspections performed may be either a ultrasonic test (UT) or an enhanced visual test-1 (EVT-1).

(c) These two programs are indeed the same. This is a typographical error.

In Item (b) of the response to Audit Question 3.1-2, CP&L indicates that an enhanced VT-1 visual examination technique may be an acceptable technique for detecting and monitoring for cracks in the crevice region of welded AHCs; yet the staff's AMR discussion in GALL Commodity Group line item IV.B 1.1-b states that visual inspection techniques are not capable of detecting cracks that could initiate in the crevice regions of welded AHCs. In Item C. of the applicant's response to the audit question, CP&L also indicates that the RV&ISIP and the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program are equivalent.

While the staff would concur that the RV&ISIP incorporates all of the applicable ASME Section XI inspections for the RV and RV internal components, the RV&ISIP also incorporates additional augmented inspections that are recommended by the BWRVIP as industry initiatives and that go beyond those inspections that are required under Table IWB-2500-1 of Section XI of the ASME Code.

Part A: Relative to Item (b) in your response to Audit Question 3.1-2, justify how, contrary to the recommendation in GALL Commodity Group item IV.B 1.1-b, an enhanced VT-1 visual examination of the weld in a welded AHC will be capable of detected cracking in the crevice region of the AHC. If an enhanced VT-1 visual examination method is determined to be an insufficient inspection method for detecting cracks in crevice region of a welded AHC, the augmented inspection of the welded AHC should be performed using an acceptable UT technique and the responses to this RAI and NRC Audit Question 3.1-2 will need to be amended to reflect this.

Part B: Relative to Item C in your response to Audit Question 3.1-2, confirm that, although the RV&ISIP incorporates all ISI inspections required for RV and RV internal components under Table IWB-2500-1 of Section XI of the ASME Code, the scope of the RV&ISIP also includes

BSEP 05-0071 Page 29 of 51 additional augmented inspections that are recommended by the BWRVIP as industry initiatives and is therefore considered to be a more comprehensive inspection program for the RV and RV internals than is the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and I1WD Program.

RAI B.2.28-6 Response Part A: The AHC welds are discussed in GALL under item IV.B1.1-d not IV.B1.1-b.

BSEP has performed inspections of the AHC welds using UT. These inspections were observed by the NRC as documented in a letter from A.F. Gibson, Division of Reactor Safety (USNRC) to R.A. Anderson, BSEP,

Subject:

NRC Inspection Report Nos. 50-325/94-10 and 50-324/94-10, dated May 16, 1994.

In letter Serial: BSEP 94-0335, dated August 24, 1994, BSEP provided the thirty-day response to Generic Letter 94-03. It states:

A VT and UT inspection found no indication at the AHC welds...

The Reactor Vessel and Internals Structural Integrity Program specifies that the AHCs are inspected to the recommendations of General Electric Company (GE) Service Information Letter (SIL) No. 462, Revision 1, "Access Hole Cracking," March 22, 2001. The inspections are as follows:

Component Baseline Re-inspection Scope Expansion Documentl Access Hole 100% of Increase Re-Covers Every 4 years inspection SIIL462 (AHC-0, 180)

Accessible frequency In NUREG-1796, "Safety Evaluation Report Related to the License Renewal of the Dresden Nuclear Power Station, Units 2 and 3 and Quad Cities Nuclear Power Station, Units 1 and 2," the NRC staff found this inspection strategy acceptable. In Section 3.1.2.3.6, on page 3-115, NUREG-1796 states:

The inspection requirements of GE SIL462, Revision 1, include visual and ultrasonic examination of the welded access hole covers. The staff finds the applicant's use of GE SE 462, Revision 1, for inspecting welded access hole covers acceptable because it is consistent with the recommendations of NUREG-1801, Item IV.B 1.1.4.

Therefore, the inspection strategy for the AHCs at BSEP is consistent with the recommendations of NUREG-1801, Item IV.B1.1.4.

Part B: As stated in the response to Audit Question 3.1-2(a), the Reactor Vessel and Internals Structural Integrity Program is a comprehensive program that incorporates ASME, BWRVIP, and NRC recommended inspections. See Table 4-1 of BWRVIP-74-A.

BSEP 05-0071 Enclosure I Page 30 of 51 Audit Question 3.1-2(c) asks:

Note that the AMPs credited for the Core Shroud and Core Plate (Access Hole Cover, Shroud Support Structure, and Thermal Sleeve) and for Jet Pump Assemblies (Holddown Beams, Diffuser) include Reactor Vessel Internals Structural Integrity Program instead of Reactor Vessel and Internals Structural Integrity Program. Explain if these two AMPs are the same.

This question involved the comparison of the terminology used in Table 3.1.2-1 and the rest of the LRA. Table 3.1.2-1 used the terminology "Reactor Vessel Internals Structural Integrity Program." The rest of the LRA used the terminology "Reactor Vessel and Internals Structural Integrity Program." As was noted in the response to the audit question, the missing and was a typographical error.

NRC RAI B.2.28-7/3.1.2.3.1.2-3 Parts A and B - on the [Detection of Aging Effects] and [Monitoring and Trending]

Program Attributes for the RV&ISIP:

Part A: In CP&L's AMR for the core spray nozzles, as given in LRATable 3.1.2-1, CP&L identifies that flow blockage is an AERM for the BSEP-1/2 core spray nozzles and credits the RV&ISIP with management of this aging effect. BWRVIP Topical Report No. BWRVIP-1 8-A, "BWR Core Spray Internals Inspection and Flaw Evaluation Guidelines," as approved in the NRC's FSER of December 7, 2000, provides the BWRVIP's recommended inspections and flaw evaluation methods for RV internal core spray lines and their subcomponents. The NRC-approved topical report focuses on the management of cracking and loss of material in these components, but does not appear to focus on how flow blockage will be managed in core spray nozzles. Identify all aging mechanisms (fouling mechanisms) that are considered to capable of impeding the flow of emergency coolant through the core spray nozzles. Clarify how the RV&ISIP will implemented to detect flow blockage of the core spray nozzles. With respect to this request, identify what type of inspection method will used to detect flow blockage in the core spray nozzles, what sample size of nozzles will be inspection as part of the inspection, and what frequency will be implemented for reinspection of the components. Identify whether CP&L's inspection method for detecting and monitoring for flow blockage is within the scope of Topical Report BWRVIP-18-A, and if not, justify why a plant-specific commitment would not be necessary for these inspections. In addition, clarify what mitigative programs or activities will be implemented, if any, to mitigate flow blockage in the core spray nozzles.

Part B: The staff has noted that Table 3.1.2-1 of the BSEP-1/2 LRA includes an AMR analysis for the internal non-safety related feedwater spargers. In this AMR, CP&L identifies that cracking and loss of material are AERMs for the internal feedwater spargers. Clarify whether the feedwater spargers are designed with spray nozzles, and if so, provide your justification why flow blockage due to fouling is not an AERM for the non-safety related feedwater sparger nozzles. If flow blockage due to fouling is an AERM for the feedwater sparger nozzles, clarify how the RV&ISIP will implemented to detect flow blockage of the feedwater sparger nozzles.

BSEP 05-0071 Page 31 of 51 With respect to this request, identify what type of inspection method will used to detect flow blockage in the feedwater sparger nozzles, what sample size of nozzles will be inspection as part of the inspection, and what frequency will be implemented for reinspection of the components.

Since aging management of the feedwater sparger and nozzles is not yet within the scope of an NRC-approved BWRVIP Topical Report, justify why a plant-specific commitment would not be necessary for these inspections. In addition, clarify what mitigative programs or activities will be implemented, if any, to mitigate flow blockage in the feedwater sparger nozzles.

RAI B.2.28-7/3.1.2.3.1.2-3 Response Part A:

Corrosion products associated with loss of material are considered capable of impeding the flow of emergency coolant through the core spray nozzles. As shown in Table 3.1.2-1, flow blockage due to fouling is managed with a combination of the Water Chemistry Program and the Reactor Vessel and Internals Structural Integrity Program. The Water Chemistry Program mitigates the formation of corrosion products by controlling oxygen, chlorides, sulfates, etc. The verification that the Water Chemistry Program is effective is through the use of the Reactor Vessel and Internals Structural Integrity Program. The inspection of the core spray components is through BWRVIP-18-A. The NRC has previously found that the use of inspections per the BWRVIP guidelines is adequate.

Section 2.3.2.3 of NUREG-1803, "Safety Evaluation Report Related to the License Renewal of the Edwin I. Hatch Nuclear Plant, Units 1 and 2," states:

In the call made on June 26, 2000, the staff expressed concern that blockage of the spray holes of the core spray spargers through aging could keep the core spray system from performing its intended function of spraying the fuel bundles following a LOCA, and thus may fail to provide adequate core cooling for the short-and long-term following the LOCA. The applicant replied that, because the core spray piping is made of stainless steel, corrosion is not a credible aging mechanism to cause flow blockage. The applicant further stated that BWRVIP-18, "Core Spray Internals Inspection and Flaw Evaluation Guidelines," provides a means to inspect the core spray piping. The staff believes that adequate long-term core cooling can only be assured by maintaining the original core spray distribution that was assumed for the CLB. The staff, therefore, will rely on the BWRVIP inspection program to provide reasonable assurance that the original spray distribution will be maintained during the period of extended operation.

Therefore, the combination of the Water Chemistry Program and the Reactor Vessel and Internals Structural Integrity Program will be effective in managing flow blockage due to fouling during the period of extended operation.

Part B:

The feedwater spargers do not have spray nozzles but have flow holes. The non-safety related feedwater spargers have been included within the scope of license renewal because of the potential for affecting safety related subcomponents of the reactor vessel and internals.

The intended function of the feedwater spargers is M4; i.e., provide structural support/seismic integrity. The feedwater spargers are managed to ensure gross structural integrity to prevent the formation of loose parts.

BSEP 05-0071 Page 32 of 51 NRC RAI B.2.28-8 On the [Detection of Aging Effects] and [Monitoring and Trending] Program Attributes for the RV&ISIP: The staff has determined that, in Table 3.1.2-1 of the LRA, CP&L identifies that cracking due to stress corrosion cracking (SCC) and/or irradiation assisted stress corrosion cracking (IASCC) and loss of materials due to pitting or crevice corrosion are applicable aging effects requiring management (AERMs) for four non-safety related RV internal components:

(1) steam dryers, (2) core shroud head and separators, (3) internal feedwater spargers, and (4) the RV surveillance capsule holders. The staff also determined that the applicant has credited the RV&ISIP with the management of these aging effects/aging mechanisms during the periods of extended operation for BSEP-1/2.

Clarify how the RV&ISIP will be used to manage cracking and loss of material that could potentially occur in the non-safety related steam dryers, core shroud headers and separators, the feedwater spargers, and surveillance capsule holders during the periods of extended operation for BSEP-1/2. Include in your discussion what type of inspection method or methods will be used to manage these aging effects, what sample size of the steam dryers (in terms of percent area inspected) will be covered by the examinations, what frequency will be used for re-examination of the steam dryers, and what corrective actions will be taken by BSEP-1/2 if cracking or loss of material is detected in the steam dryers as a result of the examinations. The staff is of the opinion the current set of BWRVIP Topical Reports do not address license renewal aging management strategies/activities for these non-safety related RV internal components. Therefore the staff also requests that the CP&L address the staff's request that a plant-specific commitment be included in the application that the RV&ISIP will be used to manage cracking and loss of material in the non-safety related steam dryers, core shroud headers and separators, the feedwater spargers, and surveillance capsule holders during the periods of extended operation for BSEP-1/2 (Refer to RAI B.2.28-15, Part B).

RAI B.2.28-8 Response A plant-specific commitment will be added stating that the Reactor Vessel and Internals Structural Integrity Program, in conjunction with the Water Chemistry Program, as appropriate, will be used to manage the non-safety related steam dryers, core shroud head and separators, feedwater sparger, and surveillance capsule holders. The revised commitment is provided in the response RAI B.2.28-15, Part B.

The four non-safety related components are managed with a combination of the Water Chemistry Program and the Reactor Vessel and Internals Structural Integrity Program. The Water Chemistry Program controls contaminants such as oxygen, chlorides, sulfates, etc., to mitigate cracking due to SCC and loss of material due to crevice and pitting corrosion. Inspections performed by the Reactor Vessel and Internals Structural Integrity Program verify the effectiveness of the Water Chemistry Program. Inspections of the steam dryers are performed according to the requirements of GE SIL No. 644, Supplement 1, "BWR Steam Dryer Integrity."

GE SIL No. 644 recommends that for a BWR/4 that a visual inspection (i.e., "best effort" VT-1)

BSEP 05-0071 Page 33 of 51 should be performed prior to initial operation above the original licensed thermal power or within the next two scheduled refueling outages if already operating above the original licensed thermal power and that the inspection should include the most susceptible locations as determined by a dryer stress analysis, including the vertical rib areas on each of the outer hoods and the end plates on the two outermost banks. Inspections of the feedwater spargers and flow holes are performed to the requirements specified in NUREG-0619, "BWR Feedwater Nozzle and Control Rod Drive Return Line Nozzle Cracking."

Cracking due to cyclic loading of the steam dryers is managed by inspections performed according to the requirements of GE SIL No. 644 Supplement 1, "BWR Steam Dryer Integrity."

The BWRVIP has recently issued BWRVIP-139, "BWR Vessel and Internals Project, Steam Dryer Inspection and Flaw Evaluation Guidelines," EPRI Technical Report 1011463, April 2005.

BSEP will follow the guidance of BWRVIP-139 when it has been reviewed and approved by the NRC.

Currently there are no inspection requirements related to the core shroud head and separators or the surveillance capsule holder. However, if the BWRVIP incorporates inspection requirements for these components BSEP will follow the guidance.

Therefore, the combination of the Water Chemistry Program and the Reactor Vessel and Internals Structural Integrity Program will be effective in managing the aging effects of the non-safety related subcomponents of the reactor vessel and internals during the period of extended operation.

NRC RAI B.2.28-9 CP&L's Collective Response to Applicant Action Item No. 2 on BWVRVIP Topical Report Numbers BWRVIP-74-A, -18, -25, -26, -27, -38, -41, -47, -48, and -49: The staff has confirmed that the applicant has satisfied 10 CFR 54.21(d) by FSAR Supplement summary descriptions for each AMP and TLAA in the LRA, but has only generally commented on the BWRVIP programs that may be invoked as part of these AMPs or TLAAs. To make the response to AAI No. 2 consistent with this determination, the staff recommends that the applicant replace the response with the following sentences:

"To satisfy the requirements of 10 CFR 54.21(d), the FSAR Supplement for the BSEP-1/2 LRA includes a summary description for each AMP and TLAA that is within the scope of the LRA. Should the scope of a specific AMP or TLAA invoke a specific BWRVIP report as a subset of the AMP or TLAA, the summary description will state that CP&L is an active participant in the BWRVIP programs, and that CP&L will implement the guidelines of the applicable BWRVIP report, as approved in the NRC's final safety evaluation report on the specific BWRVIP guideline."

The change in the response to AAI No. 2 will make the AAI response consistent with the manner in which CP&L has worded its FSAR Supplement summary descriptions to comply with 10 CFR 54.21(d).

BSEP 05-0071 Page 34 of 51 RAI B.2.28-9 Response BSEP will update its response to Applicant Action Item 2, for each of the applicable BWRVIP reports, based on the recommendations. Also see the response to RAI B.2.28-15 below.

NRC RAI B.2.28-10 CP&L's Response to Applicant Action Item No. 4 on BWRVIP Topical Report Number BNVRVIP-74-A: Pending the proposed resolution discussed in the staffs conference calls with CP&L dated April 28, 2005, and May 2, 2005, Draft RAI B.2.28-10 has been deleted from the staffs review.

RAI B.2.28-10 Response No response is required.

NRC RAI B.2.28-11 Parts A and B - CP&L's Response to Applicant Action Item No. 5 on BWVRVIP Topical Report Number BWRVIP-25: In CP&L's response to AAI No. 5 on BWRVIP-25, the applicant stated that an analysis by CP&L determined that only 48 of the 72 rim hold-down bolts in each of the BSEP-1/2 core plates were needed to maintain the structural integrity of the plates.

CP&L has stated that it confirms the presence of an adequate number of bolts by performing a UT inspection of the outside diameter of the core support ring. The examination performed by CP&L to maintain the structural integrity of the core plate and rim hold-down bolts is different from that recommended by the BWRVIP in BWRVIP-25. The staff requests that CP&L provide the following additional clarifications relative to the alternative UT examinations that are proposed for the core plate rim hold-down bolts:

Part A: Pursuant to conformance with the criteria of the "Implementation of BWRVIP Documents" process in BWRVIP-94, state whether CP&L's alternative UT examination of the outside diameter of the core support plate has been identified as an alternative to the recommended inspections of core plate rim hold-down bolts, as defined in BWRVIP-25, and whether a justification for the altemative examinations has been approved by the staff. If the UT examinations of the outside diameter of the core support rings have been approved by the staff as an alternative to the recommended BWRVIP-25 examinations of the core plate rim hold-down bolts, identify which CP&L submittal requested approval of the alternative examination method and which NRC safety evaluation provided the staffs approval of the alternative examination method.

Part B: If CP&L's alternative UT examination method for the core plate rim hold down bolts has not been approved by the NRC as an alternative to the BWRVIP-25 recommendations, clarify, using a sufficient technical basis, how the alternative examinations will be capable of

BSEP 05-0071 Enclosure I Page 35 of 51 detecting cracking or potential stress relaxation in the BSEP-1/2 core plate rim hold-down bolts and will be capable of achieving the same objective as the recommended examinations for core plate rim hold-down bolts, as defined in BWRVIP-25. Provide a commitment of the LRA that the alternative UT examinations of the core plate rim hold down bolts, as approved by the NRC, from the outside diameter of the core plate will be implemented during the periods of extended operation for BSEP-1/2 (Refer to RAI B.2.28-15, Part B).

RAI B.2.28-11 Response Part A:

BSEP's alternative examination technique has not been specifically reviewed and approved by the NRC. However, an inspection strategy, based on a plant-specific analysis, is already allowed by BWRVIP-25 and has been accepted in both the December 19, 1999, and December 7, 2000, Safety Evaluation Reports (SERs):

USNRC letter to C. Terry, BWRVIP Chairman,

Subject:

Final Safety Evaluation of BWRVIP Vessel and Internals Project, "BWR Vessel and Internals Project, BWR Core Plate Inspection and Flaw Evaluation Guideline (BWRVIP-25)," EPRI Report TR-107284, December 1996, dated December 19, 1999.

Letter from C.I. Grimes, USNRC to C. Terry, BWRVIP Chairman,

Subject:

Safety Evaluation for Referencing of BWR Vessel and Internals Project, BWR Core Plate Inspection and Flaw Evaluation Guidelines (BWRVIP-25) Report for Compliance with the License Renewal Rule (10 CFR PART 54) and Appendix B, BWR Core Plate Demonstration of Compliance with the Technical Information Requirements of the License Renewal Rule (10 CFR 54.21), December 7, 2000.

BSEP will continue to perform these inspections until such time as a revised version of BWRVIP-25 is reviewed and approved.

Table 3-2 of BWRVIP-25 describes the inspection strategy for the rim hold-down bolts. It states:

Perform enhanced VT-1 from below the core plate (or UT from above the core plate once the technique is developed) of 50% of the hold-down bolts. Reinspection strategy to be based on plant-specific analyses to assure that critical number of bolts are intact to prevent lateral displacement of the core plate.

It further states:

Analysis of plant-specific bolt configuration and loading, combined with inspection results, is required to determine if lateral restraint of the core plate is maintained.

Section 3.0 of the SER for BWRVIP-25, issued December 19, 1999, documents the findings of the initial SER, dated April 28, 1999, and subsequent BWRVIP correspondence, as follows:

Based on the structural analysis presented in this report, the BWRVIP has determined that the rim hold-down bolts are the only core plate locations which need to be addressed with

BSEP 05-0071 Page 36 of 51 a plant-specific inspection strategy. The BWRVIP has concluded that one of two plant-specific options for addressing the IGSCC susceptibility of the hold-down bolts can be selected:

1. inspect the core plate bolts to assure an adequate number are intact to prevent lateral displacement of the core plate; or,

2. install core plate wedges (BWR/6s already have wedges included in their designs) to structurally replace the lateral load resistance provided by the rim hold-down bolts, in which case no inspections are required.

The BWRVIP-25 report presents a "baseline" approach for the first inspections performed. Acceptable alternatives to inspection to new BWRVIP requirements for the core plate are also presented for plants to consider, specifically involving plant-specific analysis or repairs and/or modifications. Reinspection scope and frequency have not been determined, but will be developed later based on "baseline" inspection results.

The staff believes that an initial baseline inspection should be comprehensive, and include all components that are practicable to inspect, based on tooling available.

Further, the staff believes that a re-inspection schedule and scope, based on the performance and results of the initial baseline inspections, should be addressed. The staff requests that the BWRVIP address these in a revision to the BWRVIP-25 report.

BWRVIP's October 6, 1999, Response:

In developing inspection recommendations for the core plate (and all other internal components), the BWRVIP first evaluated whether the failure of a particular location (e.g., weld, bolted connection, etc.) could cause a degradation in plant safety. If the failure affects the ability of the plant to safely shut down, an inspection of that location is required. If not, no inspection is required. This strategy is adequate to ensure plant safety. Performing a baseline inspection of locations which, if failed, have no affect on plant safety, would require an unnecessary increase in outage time in addition to the cost associated with developing and qualifying additional inspection tooling. Consequently, the BWRVIP does not agree with the NRC suggestion that all locations on the core plate be inspected in a comprehensive baseline inspection.

Regarding definition of re-inspection scope and frequency: the Guideline states that reinspection scope and frequencies should be developed by each licensee based on the results of the baseline inspection (of core plate bolts). This approach (as opposed to the definition of generic re-inspection requirements) was necessary due to the fact that the number of bolts required for core plate integrity can be plant-specific. Definition of reinspection requirements, as requested by the NRC, has been addressed in the Guideline.

Staff's Evaluation:

The staff finds that the BWRVIP's response adequately addressed this item.

BSEP 05-0071 Page 37 of 51 The SER of dated December 7, 2000 states:

Inspection and flaw evaluation are performed in accordance with the BWRVIP-25 guidelines, which specifies ultrasonic or visual examinations (EVT-1), as approved by the NRC.

It was recognized and accepted in the December 19, 1999, SER that the number of bolts required for core plate integrity can be plant-specific. The December 7, 2000, SER does not change this recognition. An inspection strategy based on a plant-specific analysis is already accepted practice under BWRVIP-25.

A detailed review of the AMR for the hold-down rim bolts is provided.

The AMR for the rim hold-down bolts, as part of the "Core Shroud and Core Plate (Core Plate Bolts)" commodity, predicted the following aging effects, other than the potential for fatigue:

Loss of Material due to Crevice Corrosion Loss of Material due to Pitting Corrosion Cracking due to SCC These aging effects are managed by a combination of the Water Chemistry Program and the Reactor Vessel and Internals Structural Integrity Program. Loss of preload due to stress relaxation was not an applicable aging effect. NRC Inspection Manual, Inspection Procedure 71002, dated September 18, 2000, defines a plausible aging effect as follows:

An effect, related to an SC, under generally applicable conditions, having the potential for affecting the SC's ability to perform its intended function.

The same inspection procedure defines an "applicable aging effect" as follows:

An effect, related to an SC because of its design, configuration, material makeup, and environment, that if not prevented or mitigated, will result in the degradation that will affect the component's ability to perform its intended function.

As stated in the response to Applicant Action Item 5 to BWRVIP-25, BSEP has performed a plant-specific evaluation that has determined that the core plate rim hold-down bolts can perform their intended function without benefit of preload.

Therefore, loss of preload due to stress relaxation is a "plausible aging effect" but it is not an "applicable aging effect."

Part B:

As discussed in the response to Part A of this RAI, the inspection technique is not required to detect loss of preload due to stress relaxation because it is not an "applicable aging effect." Cracking due to SCC is managed by the combination of the Water Chemistry Program

BSEP 05-0071 Page 38 of 51 and the Reactor Vessel and Internals Structural Integrity Program. The Water Chemistry Program is a mitigative program. The goal of the inspection strategy performed under the Reactor Vessel and Internals Structural Integrity Program is not to ensure that cracking is detected but to ensure that the plant-specific number of bolts is present. Maintaining the presence of the required number of bolts determined by the plant-specific analysis ensures that the intended function of the rim hold-down bolts is maintained during the period of extended operation.

NRC RAI B.2.28-12/4.2-3 CP&L's Response to Applicant Action Item No.4 on BWRVIP Topical Report Number BWRVIP-26: Pending the proposed resolution discussed in the staffs conference calls with CP&L dated April 28, 2005, and May 2, 2005, Draft Joint RAI B.2.28-12/RAI 4.2-3 has been deleted from the staff's review.

RAI B.2.28-12/4.2-3 Response No response is required.

NRC RAI B.2.28-13/4.3-1 CP&L's Response to Applicant Action Item No.4 on BWRVIP Topical Report Number BWRVIP-27: In its response to AAI No.4 on BWRVIP-27 (as given in "Table 5 - BWRVIP-27" of the RV&ISIP), CP&L stated that fatigue of the shroud supports was included as a TLAA in Chapter 4 of the BSEP-1/2 LRA. The BWRVIP issued BWRVIP-27 to provide the U.S. BWR industry with recommended guidelines and flaw evaluation criteria for standby liquid control(SLC)/core AP line penetrations to BWR RVs.

The scope of the topical report does not cover core shroud supports. Thus, any response by the applicant to AAI No. 4 on BWRVIP-27 should have been in reference to the need to assess whether a TLAA fatigue analysis is needed for the SLC/core AP lines penetrations of the BSEP-1/2 RVs. The staff requests that CP&L provide a revised response to AAI No. 4 on BWRVIP-27 that is relevant to a determination on whether the SLC/core AP lines is a fatigue analysis TLAA.

If in the revised response, CP&L determines that fatigue of the SLC/core AP lines is not a TLAA to the BSEP-1/2, justify the basis for making this conclusion relevant to the definition for a TLAA in 10 CFR 54.3 and to the Section G of staff's Statement of Consideration on 10 CFR Part 54. If CP&L determines that on thermal fatigue of the SLC/core AP lines is a TLAA, either justify how the CP&L's thermal fatigue analysis, as discussed in Section 4.3 of the LRA, covers the topic of thermal fatigue of the SLC/core AP lines, or else supplement TLAA 4.3 to include a thermal fatigue analysis for these lines for the period of extended operation.

BSEP 05-0071 Enclosure I Page 39 of 51 RAI B.2.28-13/4.3-1 Response Applicant Action Item #4 to BWRVIP-27 requires revision. The revised response to the Applicant Action Item is as follows:

There is no thermal fatigue TLAA for the AP/SLC vessel penetration/nozzle and safe-end assembly because it is exempt from a fatigue evaluation based on Paragraph N415.1 of the 1965 Edition of ASME Section III.

The AP/SLC vessel penetration/nozzle and safe-end assembly is one of the nozzles evaluated under the designation "Miscellaneous Nozzles" in Table 4.3-2 of the BSEP LRA. The Miscellaneous Nozzles were determined to be "Exempt" from a fatigue evaluation. The response to RAI 4.3-1 (i.e., Serial: BSEP 05-0050, dated May 4, 2005) provides an explanation of why components were exempted from a fatigue analysis.

NRC RAI B.2.28-14 CP&L's Response to Applicant Action Item No. 4 on BWRVIP Topical Report Number BWRVIP-47: In CP&L's response to AAI No. 4 on BWRVIP-27 (as given in "Table 8 -

BWRVJP47" of the RV&ISIP), CP&L stated that the it did not identify any fatigue-related TLAAs for the RV internal lower plenum components. In Section 3.5 of the staff's license renewal FSER on BWRVIP-47, the staff made the following statement on whether a TLAA on fatigue of the RV internal lower plenum components would be needed in an LRA for a BWR-designed light-water reactor:

"The BWRVIP-47 report stated that some plants may have lower plenum pressure boundary component fatigue cumulative usage factors (CUF) greater than the 1.0 threshold specified in NUMARC 90-02 for the license renewal term. For these plants, a plant-specific description of how this issue will be addressed will be needed.

The BWRVIP-47 report further stated that, based on the above criteria, there are no generic TLAA issues that require evaluation for the lower plenum components."

The evaluation in Section 3.5 of the staff's FSER on BWRVIP-47 focuses on a determination that a TLAA on fatigue would only needed to be included in the application if the CUF for the lower plenum components was determined to be in excess of 1.0 for the extended design life of a given BWR (54 EFPY for BSEP-1/2). To validate your determination that a TLAA does not need to be identified for the RV internal lower plenum components, the staff requests confirmation that the CUF for the RV internal lower plenum components has been determined to be less than 1.0 for the design cycles assumed through 54 EFPY.

BSEP 05-007 1 Page 40 of 51 RAI B.2.28-14 Response The response to Applicant Action Item #4 states:

No fatigue related TLAAs were identified for the Lower Plenum.

This response will be revised to provide the basis for the determination. The revised response to the Applicant Action Item is as follows:

No fatigue related TLAAs were identified for the Lower Plenum. There is no thermal fatigue TLAA for the lower plenum pressure boundary components because they are exempt from a fatigue evaluation based on Paragraph N-415.1 of the 1965 Edition of ASME Section III.

The lower plenum pressure boundary components are evaluated under the designation "Control Rod Drive (CRD) Penetrations" in Table 4.3-2 of the BSEP LRA. The CRD Penetrations were determined to be "Exempt" from a fatigue evaluation. The response to RAI 4.3-1 (i.e., Serial:

BSEP 05-0050, dated May 4, 2005) provides an explanation of why components were exempted from a fatigue analysis.

NRC RAI B.2.28-15 CP&L's FSAR Supplement Summary Description and Commitment for the RV&ISIP:

Part A: The staff requests that the FSAR Supplement summary description for the RV&ISIP, as given in Section A.1.1.30 of the LRA, be supplemented to include the following items:

1. A statement that scope of the RV&ISIP includes conformance with and implementation of applicable BWRVIP Topical Reports, including BWRVIP-18, -25, -26, -27, -38, -41,

-47, -48, -49, A, -76, and -94.

2. A statement that the RV&ISIP will be used to manage loss of preload/stress relaxation in the BSEP-2 spring-loaded core plate plugs by the implementing augmented inspections of the BSEP-2 spring-loaded core plate plugs during the period of extended operation for BSEP-2.

3. A statement that the RV&ISIP will be used to manage flow blockage of the core spray nozzles by implementing augmented inspections of the core spray nozzles during the periods of extended operation for BSEP-1/2.

4. A statement the RV&ISIP will be used to manage cracking and loss of material in the non-safety related steam dryers, feedwater spargers, core shroud holders and separators, and RV surveillance capsule holders during the periods of extended operation for BSEP-1/2.

BSEP 05-0071 Page 41 of 51 Part B: The staff requests that the existing commitment for the RV&ISIP, as given in the commitment tracking list for the BSEP-1/2 LRA (i.e., in Enclosure 1 of CP&L Serial Letter No.

BSEP 04-0006, dated October 18, 2004) be supplemented to include the following additional items:

1. A statement that scope of the RV&ISIP includes conformance with and implementation of applicable BWRVIP Topical Reports, including BWRVIP-18, -25, -26, -27, -38, -41,

-47, -48, -49, A, -76, and -94.

2. A statement that the RV&ISIP will be used to manage flow blockage of the core spray nozzles by implementing augmented inspections of the core spray nozzles during the periods of extended operation for BSEP-1/2.

3. A statement the RV&ISIP will be used to manage cracking and loss of material in the non-safety related steam dryers, feedwater spargers, core shroud holders and separators, and RV surveillance capsule holders during the periods of extended operation for BSEP-1/2.

4. A statement that the alternative UT examinations of the core plate rim hold down bolts, from the outside diameter of the core plates, as submitted as an exception to the BWRVIP-25 recommendations and approved by the NRC, will be implemented during the periods of extended operation for BSEP-1/2 (This commitment will only be need if the UT examination method for the core plate rim hold down bolts from the outside diameter of the core support rings has not been approved by the NRC as an acceptable supplemental inspection method and has yet to be incorporated into an NRC-approved revision of the BWRVIP-25 recommendations - Refer to RAI B.2.28-11, Part B).

RAI B.2.28-15 Response Part A.1: The response to RAI B.2.28-1 (i.e., provided previously in this submittal) states that the following documents are part of the Reactor Vessel and Internals Structural Integrity Program:

BWRVIP-18 BWRVIP-25 BWRVIP-26 BWRVIP-27 BWRVIP-38 BWRVIP-41 BWRVIP-47 BWRVIP-48 BWRVIP-49 BWRVIP-74-A BWRVIP-76 BWRVIP-94 This response also applies to Part B.1.

Part A.2: The response to RAI B.2.28-5 documents that the Reactor Vessel and Internals Structural Integrity Program (i.e., BSEP LRA Section B.2.28) will manage loss of preload due to stress relaxation of the spring-loaded core plate plugs installed in Unit 2 by replacement.

Part A.3: The response to RAI B.2.28-7 documents that flow blockage due to fouling of the "Core Spray Lines and Spargers (Spray Nozzles)" will be managed with a combination of the

BSEP 05-0071 Page 42 of 51 Water Chemistry Program and the guidelines of BWRVLP-18 which are part of the Reactor Vessel and Internals Structural Integrity Program. This response also applies to Part B.2.

Part A.4: The response to RAI B.2.28-8 documents the aging management activities for non-safety related Steam Dryers, Feedwater Spargers, Shroud Head and Separators, and Surveillance Capsule Holders. This response also applies to Part B.3.

Part B.4: The response to RAI B.2.28-1, Parts A and B, documents that BSEP inspection strategy for the core plate rim hold-down bolts are per the existing BWRVIP-25 requirements.

No unique commitment is required.

Based on the above information, Updated Final Safety Analysis Report (UFSAR) Supplement, LRA Section A.1.1.30, has been revised to read as follows:

A.1.1.30 Reactor Vessel and Internals Structural Integrity Program The Reactor Vessel and Internals Structural Integrity Program includes inspection of reactor vessel and internal components in accordance with the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program and inspection and flaw evaluation in conformance with the guidelines of applicable Boiling Water Reactor Vessel and Internals Project (BWRVIP) documents. In addition, monitoring and control of reactor coolant water chemistry, through the use of the BSEP Water Chemistry Program, in accordance with the latest guidelines of the BWRVLP, helps ensure the long-term integrity and safe operation of the Reactor Vessel and Internals components. This Program has been prepared using BWRVIP-74-A, BWR Reactor Pressure Vessel Inspection and Flaw Evaluation Guidelines for License Renewal, and was based on the guidance set forth in BWRVIP-94, BWR Vessel and Internals Project Program Implementation Guide. The scope of the Program includes the following activities performed in accordance with following or latest BWRVIP guidelines:

Activity BWRVIP Guideline Core Spray Internals Inspection and Flaw Evaluation including BWRVIP-18 management of potential fouling of Core Spray lines and spargers.

Core Plate Inspection and Flaw Evaluation BWRVIP-25 Top Guide Inspection and Flaw Evaluation BWRVIP-26 Standby Liquid Control System/Core AP Inspection and Flaw BWRVIP-27 Evaluation Shroud Support Inspection and Flaw Evaluation BWRVIP-38 Jet Pump Assembly Inspection and Flaw Evaluation BWRVIP-41 Lower Plenum Inspection and Flaw Evaluation BWRVIP-47 Vessel ID Attachment Weld Inspection and Flaw Evaluation BWRVIP-48 Instrument Penetration Inspection and Flaw Evaluation BWRVIP-49 Core Shroud Inspection and Flaw Evaluation BWRVIP-76 The scope of the Program includes aging management of steam dryers, feedwater spargers, shroud head and separators, and surveillance capsule holders. Loss of preload due to stress

BSEP 05-0071 Page 43 of 51 relaxation of the Unit 2 spring-loaded core plate plugs will be managed by replacing the plugs.

Flow blockage due to fouling of the "Core Spray Lines and Spargers (Spray Nozzles)" will be managed with a combination of the Water Chemistry Program and the guidelines of BWRVIP-1 8.

Prior to the period of extended operation, the Program will be enhanced to: (1) incorporate augmented inspections of the top guide using enhanced visual examination or other acceptable inspection methods that will focus on the high fluence region and (2) establish inspection criteria for the VT-3 examination of the Core Shroud Repair Brackets.

Based on the above information, the commitment to the Reactor Vessel and Internals Structural Integrity Program will be revised to state:

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Reactor Vessel and A.1.1.30 Prior to the period of extended operation, the Reactor Vessel and Internals Internals Structural Structural Integrity Program will be enhanced to: (1) incorporate augmented Integrity Program inspections of the top guide using enhanced visual examination or other acceptable inspection methods that will focus on the high fluence region, (2) establish inspection criteria for the VT-3 examination of the Core Shroud Repair Brackets, (3) the scope of the program described in the UFSAR Supplement will be revised to state that the program implements the following or latest BWRVIP guidelines:

BWRVIP-18, BWRVIP-25, BWRVIP-26, BWRVIP-27, BWRVIP-38, BWRVIP-41, BWRVIP-47, BWRVIP-48, BWRVIP-49, BWRVIP-74-A, BWRVIP-76, and BWRVIP-94.

and (4) the scope of the program described in the UFSAR Supplement will be revised to state that:

the Reactor Vessel and Internals Structural Integrity Program in conjunction with the Water Chemistry Program will be used to manage flow blockage due to fouling of the Core Spray lines and spargers (spray nozzles),

the Reactor Vessel and Internals Structural Integrity Program will be used to manage the aging of the non-safety related steam dryers, feedwater spargers, shroud head and separators, and surveillance capsule holders, and loss of preload due to stress relaxation of the Unit 2 spring-loaded core plate plugs will be managed by replacing the plugs.

BSEP 05-0071 Page 44 of 51 NRC RAIs 2.3.3.7-9a and 2.3.3.7-9b (Supplemental Response)

Original RAI 2.3.3.7-9a stated: 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.

Original RAI 2.3.3.7-9b stated: 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 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.

NRC RAIs 2.3.3.7-9a and 2.3.3.7-9b Supplemental Response PEC letter to the NRC (Serial: BSEP 05-0050), dated May 4, 2005, provided the original responses to these RAIs. Following further discussions with the NRC staff, BSEP is providing the following supplemental information.

RAIs 2.3.3.7-9a and 2.3.3.7-9b were issued to clarify the basis for the scoping boundary being ended in the middle of lines depicted on License Renewal boundary drawings D-02537-LR, Sheet 2 and D-25037-LR, Sheet 2, at location B-2 on both drawings. The BSEP response to these RAIs was that the extent of highlighted piping represents the boundary for the seismic analysis associated with the safety related/non-safety related boundary occurring at 1/2-ElI-F073. The NRC has noted that the boundary depicted on the License Renewal boundary drawings is adjacent to 1/2-El1-F074, and expressed concern regarding whether the response to RAIs 2.3.3.7-9a and 2.3.3.7-9b represents a shift in scoping boundaries.

A review of the response to RAIs 2.3.3.7-9a and 2.3.3.7-9b confirms that the 1/2-E11-F073 valve is the safety related/non-safety related boundary of interest, and the extent of piping highlighted as in scope is correct. The seismic extension at this location does begin at the 1/2-Ell-F073 valves and extends through the 1/2-E11-F074 valves to the terminus indicated on the referenced flow diagrams. Piping through this point is in License Renewal scope and subject to AMR. No components were removed from scope as a result of the BSEP response to RAIs 2.3.3.7-9a and 2.3.3.7-9b.

BSEP 05-0071 Page 45 of 51 NRC RAI 3.5-8 (Supplemental Response)

The original RAI stated: 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 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 BSEP.

RAI 3.5-8 Supplemental Response PEC letter to the NRC (Serial: BSEP 05-0050), dated May 4, 2005, provided the original response to this RAI. Following further discussions with the NRC staff on May 18, 2005, BSEP is providing the following supplemental information.

The ASME Section XI, Subsection IWF and Structures Monitoring Programs do not specifically address Lubrite; however, the inspection criteria for supports within the programs effectively envelope misalignment and accumulation of debris.

NRC RAI 4.2-2 (Supplemental Response)

The original RAI stated: 10 CFR 54.3 provides that staffs criterion for determining whether a given plant analysis is within the scope of the definition for a TLAA. 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).

BSEP 05-0071 Page 46 of 51 RAI 4.2-2 Supplemental Response PEC letter to the NRC (Serial: BSEP 05-0050), dated May 4, 2005, provided the original response to this RAI. Following further discussions with the NRC staff, BSEP is providing the following supplemental information.

This TLAA is added to the USFAR Supplement as follows:

A.1.2.1.9 Reactor Vessel Reflood Thermal Shock 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 Loss of Coolant Accident (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, with E > I MeV, at the mid-core inside of the vessel was 2.4 x 1017 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.

For License Renewal, 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 G 15.

The reactor vessels at BSEP are BWR/4. 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 basis 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 BWRI6 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 BWRI6 analysis is considered applicable to the BSEP reactor vessels, and is considered to be a revised analysis for License Renewal. The BWRI6 analysis assumes 40-year end-of-life material toughness, which in turn depends on end-of-life adjusted reference temperature. The critical location for the fracture mechanics analysis is at /4 of the vessel thickness from the inside (i.e., 1/T). 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 1/4/4T, is approximately 400'F.

The worst-case calculated adjusted reference temperature resulting from 54 EFPY radiation exposure (i.e., 60 years) was determined to be 136.10F, which is well below the 400'F 1/4AT temperature predicted for the thermal shock event at the time of peak stress intensity. Therefore, the BSEP reactor vessel reflood thermal shock analysis has been projected to the end of the period of extended operation.

BSEP 05-0071 Page 47 of 51 NRC RAI 4.7.4-1 (Supplemental Response)

The original RAI stated: The torus liner and the ASME,Section XI, ISI component supports are dispositioned through 10 CFR 54.21(c)(1)(ii). In its description of the analyses, the applicant states:

The corrosion rate in the immersion zone was determined to be 0.00 116 inch/year based on plant calculations and measurements. The general corrosion rate for the vapor zone is conservatively assumed to be the same as the immersion zone.

... [For ASME,Section XI, ISI Component Supports the evaluation considered], the number of sides of the component exposed to the Torus environment and the time at which the component had been installed.

The staff requests the applicant to describe the most recent significant inspection findings for the selected ASME,Section XI, ISI components, and the Code inspection requirements for these components.

The staff requests the applicant to provide details of the plant calculations and measurements to support the use of the 0.00116 inch/year corrosion rate.

The additional information should include a description of the corrosion monitoring program (discussed during the January 12, 2005, teleconference call) from which the 0.00116 inches/year corrosion rate was determined. In addition, the applicant should indicate the number and frequency of coupons removed and tested.

The staff also requests the applicant to discuss the frequency and results of the wall thickness measurements in the vapor zone to support the assertion that the corrosion rate for the immersion zone is a conservative assumption for the corrosion rate in the vapor zone.

RAI 4.7.4-1 Supplemental Response PEC letter to the NRC (Serial: BSEP 05-0044), dated March 31, 2005, provided the original response to this RAI. Following further discussions with the NRC staff on May 18, 2005, BSEP is providing the following supplemental information.

All accessible uncoated component support locations above the waterline in each torus have been visually examined by the Plant Materials Engineer. These qualitative visual examinations are not used to directly validate the quantitative values present in the corrosion analyses. Instead, a One-Time Inspection is planned which will use ultrasonic testing to determine a more accurate corrosion rate. However, the visual examination results do provide meaningful information which correlates with the low corrosion rate predicted for these locations.

It should be noted that the locations which were reported to have tightly adhering corrosion are bare carbon steel surfaces with no protective coatings. Some of these surfaces had coatings removed during modification work in the early 1980's to permit welding of attachments, and

BSEP 05-0071 Page 48 of 51 these surfaces were not recoated. These surfaces exhibit general corrosion, which is expected in this environment. However, the appearance and texture of the corrosion deposits indicate the corrosion is no longer in an active state, but is proceeding at a very low corrosion rate. The dark brownish-black color of the deposit indicates the presence of magnetite, which acts as a barrier that retards further corrosion. There is no indication that the corrosion is active, as would be seen by the presence of a red or reddish brown color.

The fact that the corrosion deposit is tightly adhering indicates there is no significant amount of loose or flaking rust present. If corrosion were occurring at a high rate, the corrosion deposits would be expected to be much thicker, would be coarse and flaky, and the quantity of corrosion products would increase over time. Also, the volume of iron oxides present would also be much larger, since the volume of corrosion products produced in an active corrosion cell is normally several times larger than the volume of the steel that is consumed. However, in contrast with this, Quality Control inspection results indicate very little change has occurred in the appearance or quantity of corrosion deposits through numerous inspections of torus components performed between 1994 and 2005, indicating very low corrosion activity. One reason the corrosion deposits are not active is that the torus is inerted with nitrogen during operating cycles, which inhibits corrosion. The corrosion that is present largely occurred during refueling cycles when normal oxygen levels are present.

Rust staining occurs on coated surfaces below bare surfaces with general corrosion, where a thin oxide layer is carried by moisture and runs down over a coated surface. The presence of rust stain does not indicate there is corrosion occurring at that location, but indicates corrosion has occurred on adjacent surfaces above or near the stain.

In conclusion, the visual examination results of these corrosion deposits provide qualitative information that is consistent with the low rate of corrosion predicted in the analyses. A One-Time Inspection will be used in the future to provide quantitative information necessary to determine a more accurate corrosion rate.

NRC RAI 4.7.4-2 (Supplemental Response)

The original RAI stated: The non-ASME,Section XI, ISI component supports are dispositioned through 10 CFR 54.21(c)(1)(iii). In its description of the analyses, the applicant states:

The aging management activities will be predicated on the results of volumetric measurements performed on the components. Therefore, prior to the period of extended operation, the One-Time Inspection Program will be used to perform volumetric measurements to determine the actual rate of corrosion of the Vent Header Lower Column Support in the immersed and vapor space of the Torus, and platform steel and miscellaneous supports in the vapor space of the Torus.

BSEP 05-0071 Page 49 of 51 The staff requests the applicant to describe the baseline inspection performed and the results of the inspection for each of the non-ASME,Section XI, ISI components, from which the actual rate of corrosion will be determined.

The staff requests the applicant to discuss how the one-time inspection (OTI) Program is defined such that all the non-ASME,Section XI, ISI component supports are included within the scope of the OTI program, ultrasonically inspected, and the inspection results analyzed and evaluated for the period of extended operation.

The staff requests the applicant clarify that the description and scope for the non-ASME,Section XI, ISI component supports applies to Unit 1 or Unit 2 or both and to list the components and the environments in which these components are found (i.e., vapor zone or immersed zone or both).

RAI 4.7.4.2 Supplemental Response PEC letter (i.e., Serial: BSEP 05-0044) to the NRC, dated March 31, 2005, provided the original response to this RAI. Following further discussions with the NRC staff on May 18, 2005, BSEP is providing the following supplemental information.

Determining the corrosion rate based on subtracting the actual remaining member thickness from the original design thickness plus the mill tolerance will generate a conservative rate, because the addition of the mill tolerance maximizes the amount of material lost over the service life and provides for a higher corrosion rate. Mill tolerances are normally based on weight rather than actual thickness and the American Institute of Steel Construction Manual, page 1-125, Standard Mill Practice, identifies an area and weight variation of +/- 2.5% for typical structural members.

The corrosion rate, using the aforementioned method, is determined as follows:

Corrosion rate = (Nominal Design Thickness + Mill Tolerance) - Remaining Thickness Years of Service For Example:

The corrosion rate using the nominal design thickness plus the mill tolerance: assuming 40 years of operation for a member with a design thickness of 1 inch, a mill tolerance of 2.5%, and an actual UT measurement of 0.95 inches would be:

{[1 +(1 x.025)] -. 951/40= 1.87 mils/year.

As stated in the original response to RAI 4.7.4-2, an acceptable alternative method would be to subtract the UT measurements of uncoated areas from adjacent UT measurements of coated locations, which are un-corroded and representative of the actual original design thickness, and divide by the number of years of service to determine the actual corrosion rate.

All the components subject to this corrosion rate are located in the torus. There are only two environments in the torus, i.e., the vapor zone and immersion zone. As discussed in RAI 4.7.4-1, the corrosion rate was determined based on the immersion zone being the harshest environment

BSEP 05-0071 Page 50 of 51 and the vapor zone corrosion rate conservatively used the immersion zone rate. Therefore, the corrosion rate for the One-Time Inspection is applicable tocarbon steel in the vapor zone and in the immersion zone. A sampling process will be implemented to establish the corrosion rate for the subject components, the following guidance is provided for the sample population:

A sufficient number of locations in both the vapor and immersion zones must be chosen in order to develop a representative sample. The original rate was determined based on three UT readings from 16 locations on the liner, below the waterline, throughout the torus. Considering that locations in both the vapor zone and immersion zone are subject to this evaluation, a representative sampling in both areas is required. As such, three UT readings are proposed for four locations in the immersion zone and three UT readings are proposed for eight locations in the vapor zone. The sample locations for both the immersion and vapor zones shall be taken from components listed in the original response to RAI 4.7.4-2.

Applicant-Identified Item (Auxiliary Heat Exchangers)

During a recent review of AMR basis documents, BSEP noted discrepancies with regard to materials and environments in the AMR line items for High Pressure Coolant Injection (HPCI)

System and Reactor Core Isolation Cooling (RCIC) System lube oil coolers. The following corrections are provided for these line items in LRA Tables 3.2.2-3 and 3.3.2-2.

HPCI Lube Oil Coolers Tubing represented by "Auxiliary Heat Exchangers (Auxiliary Heat Exchanger tubing)" has a treated water internal environment, not a lube oil environment as shown in LRA Table 3.2.2-3. Crevice and Pitting Corrosion and Selective Leaching are applicable in a treated water environment and are managed by the PM Program and the Selective Leaching Program, respectively. Standard note J applies to this line item.

External surfaces of the tubing, as well as the internal surfaces of the carbon steel housing are in a lube oil environment, and no aging effects are predicted. Standard note J and plant-specific note 220 remain applicable.

RCIC Lube Oil Coolers The RCIC Lube Oil Cooler shell, represented by "Auxiliary Heat Exchangers (Auxiliary Heat Exchanger shell / housing)," is constructed of copper alloys, rather than carbon steel as shown in LRA Table 3.3.2-2, and has a lube oil internal environment. No aging effects are predicted. Standard note J and plant-specific note 334 remain applicable.

The corrected LRA table line items are shown below.

BSEP 05-0071 Page 51 of 51 Table 3.2.2-3:

Component Intended Agn fet Aging Management VoUmEG 20 Table 1 Commodity Function Material Environment Requiring Program Volume 2 Item No Management Item________

Auxiliary Heat M-1 Copper Lube Oil None None J, 220 Exchangers(A Alloys (External) uxiliary Heat Treated Water Loss of Material Preventive J

Exchanger (Internal) due To Crevice Maintenance tubing)

Corrosion Loss of Material due To Pitting Corrosion Loss of Material Selective Leaching of J

due To Selective Materials Leaching M-5 Copper Lube Oil None None J, 220 Alloys (External)

Treated Water Loss of Heat Preventive J

(Internal)

Transfer Maintenance Effectiveness due To Fouling of Heat Transfer Surfaces Table 3.3.2-2:

Component Intended Aging Effect Aging Management NUREG-2801 Table 1 Notes Commodity Function material Environment Requiring Program tluem2 ItemNoe Management Item____

Auxiliary Heat M-1 Copper Indoor Air None None J

Exchangers(Auxili Alloys (External) ary Heat Lube Oil None None J,334 Exchanger shell /

(Internal) housing)

BSEP 05-007 1 Page 1 of 5 Biunsivick SteA Electric Plant (BSEP)'License Reneal Cmiitn iion Brnwc in I

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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 FAC 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 (RHR) 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. 1.1.11 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 test/inspection methods are warranted.

BSEP 05-0071 Page 2 of 5

.Bunivwick Steami Ele ctric' Plan't(SP LcneRnewal Commiitmenifts, Revision 5 LRA-License Renewa R

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cope of Cormimitmn't Commtmnt SiQst.R L,v0 S ectioid 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 05-0071 Page 3 of 5

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~~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 05-0071 Page 4 of 5 Bruns;vick Steam Electric Plant (BSEP) License Renewal Commitment, Revision 5.,

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.<;-:° 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: (1) 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: (I) incorporate augmented inspections of the top guide using enhanced visual examination or other Integrity Program acceptable inspection methods that will focus on the high fluence region, (2) establish inspection criteria for the VT-3 examination of the Core Shroud Repair Brackets, (3) the scope of the program described in the UFSAR Revised commitment Supplement will be revised to state that the program implements the following or latest BWRVIP guidelines:

BWRVIP-18, BWRVIP-25, BWRVIP-26, BWRVIP-27, BWRVIP-38, BWRVIP-41, BWRVIP-47, BWRVIP-48, BWRVIP-49, BWRVIP-74-A, BWRVIP-76, and BWRVIP-94.

and (4) the scope of the program described in the UFSAR Supplement will be revised to state that:

the Reactor Vessel and Internals Structural Integrity Program in conjunction with the Water Chemistry Program will be used to manage flow blockage due to fouling of the Core Spray lines and spargers (spray nozzles),

the Reactor Vessel and Internals Structural Integrity Program will be used to manage the aging of the non-safety related steam dryers, feedwater spargers, shroud head and separators, and surveillance capsule holders, and

loss of preload due to stress relaxation of the Unit 2 spring-loaded core plate plugs will be managed by replacing the plugs.

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.

BSEP 05-0071 Page 5 of 5 Brunswick Steam Electric Pla SE) se Renewal Commitments eiion 5 ;;

Licns

endewLRA, ScopeofCommitment Sujct ippen' dix A,.,m.'.

.Commitment Subjct, Se.

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.

Fuel Pool Girder Tendon A. L. 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 and approval 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 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.

Potential Aging None, refer to An evaluation of plant and industry operating experience will be submitted for NRC review at least one year prior Effects/Mechanisms ACRS letter to the period of extended operation. The purpose of the evaluation will be to assure that relevant aging effects Resulting from Power report on caused by operation at power uprate conditions are adequately addressed by aging management programs.

Uprate Dresden/Quad Cities, dated September 16, 2004

v t e Letter Sequence Response to RAI
TAC:MC4639, (Approved, Closed) TAC:MC4640, (Approved, Closed)
Initiation Request, Request, Request, Request Acceptance... Supplement Administration Meeting Questions 8 April 2005 25 April 2005 18 May 2005 Answers 31 March 2005 4 May 2005 11 May 2005 14 June 2005 18 July 2005 Results Approval, Approval, Approval, Approval, Approval, Approval, Approval Other: BSEP 04-0006, Applicants Environmental Report - Operating License Renewal Stage, BSEP 05-0041, Response to Audit Questions License Renewal NUREG-1801 Consistency Audit, BSEP 05-0148, Revised License Renewal Commitment List, ML043360386, ML051570067, ML051720621
MONTHYEAR2005-05-11 [Table View]

BSEP 05-0071, Response to Request for Additional Information - License Renewal

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