JAFP-07-0021, License Renewal Application, Amendment 6

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License Renewal Application, Amendment 6
ML070520263
Person / Time
Site: FitzPatrick Constellation icon.png
Issue date: 02/12/2007
From: Peter Dietrich
Entergy Nuclear Northeast, Entergy Nuclear Operations
To:
Document Control Desk, Office of Nuclear Reactor Regulation
References
JAFP-07-0021, TAC MD2666
Download: ML070520263 (29)
v • d • e


Text

dhEn tery Entergy Nuclear Northeast Entergy Nuclear Operations, Inc.James A. Fitzpatrick NPP P.O. Box 110 Lycoming, NY 13093 Tel 315 349 6024 Fax 315 349 6480 February 12, 2007 JAFP-07-0021 Pete Dietrich Site Vice President

-JAF U.S. Nuclear Regulatory Commission Attn: Document Control Desk Washington, DC 20555-0001

REFERENCES:

-1.

Letter, Entergy to USNRC, "James A. FitzPatrick Nuclear P6wer Plant, Docket No. 50-333, License No. DPR-59, License Renewal Application," JAFP-06-0109, dated July. 31, 2006 2. Letter, USNRC to Entergy, "Requests for Additional Information Regarding the Review. of the License Renewal Application for James A. FitzPatrick Nuclear Power Plant (TAC No. MD2666)," dated January 12, 2006

SUBJECT:

Entergy Nuclear Operations, Inc., James A. FitzPatrick Nuclear Power Plant Docket No. 50-333, License No. DPR-59 License Renewal Application, Amendment 6

Dear Sir or Madam:

On July 31, 2006, Entergy Nuclear Operations, Inc. submitted the License.Renewal Application (LRA) for the James A. FitzPatrick Nuclear Power Plant (JAFN.PP) as indicated by Reference

1. Attachment 1 provides responses to the requests for additional information as detailed by the NRC in Reference 2.Should you have any questions concerning this submittal, please contact Mr. Jim Costedio at (315) 349-6358.I declare under penatly of perjury that the foregoing is true and correct. Executed on the Y-Z PETE DIETRICH SITE VICE PRESIDENT PD/cf Attachment cc: (see list)A-(Dý February 12, 2007 JAFP-07-0021 Page 2 of 2 cc: Mr. N.B. (Tommy) Le, Senior Project Manager License Renewal Branch B Office of Nuclear Reactor Regulation U.S. Nuclear Regulatory Commission Mail Stop 0-11-F1 Washington, DC 20555 Mr. Samuel J. Collins, Administrator Region I U. S. Nuclear Regulatory Commission 475 Allendale Road King of Prussia, PA 19406 NRC Resident Inspector U. S. Nuclear Regulatory Commission James A. FitzPatrick Nuclear Power Plant P.O. Box 136 Lycoming, NY 13093 Mr. John P. Boska, Project Manager Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation U.S. Nuclear Regulatory Commission Mail Stop O-8-C2 Washington, DC 20555 Mr. Paul Eddy New York State Department of Public Service 3 Empire State Plaza, 1 0 th Floor Albany, NY 12223 Mr. Peter R. Smith, President NYSERDA 17 Columbia Circle Albany, NY 12203-6399 RESPONSES TO REQUESTS FOR ADDITIONAL INFORMATION (RAIs)JAMES A. FITZPATRICK NUCLEAR POWER PLANT LICENSE RENEWAL APPLICATION SECTIONS 2.2, 2.3, 2.5, 3.1, 3.5, 4.2, 4.7, AND APPENDIXB RAI 2.2.4-1 License Renewal Application (LRA) Section 2.4.4 includes review of bulk commodities such as structural components or commodities that support intended functions of in-scope systems, structures, and components.

It is not clearfrom the review of the LRA Table 2.4-4, "Bulk Commodities Summary of Components Subject to Aging Management Review (AMR)," and Table 3.5.2-4, "Bulk Commodities Summary of Aging Management Evaluation," that the structural fire barriers (walls, ceilings, floors, and slabs) are within the scope of license renewal in accordance with Title 10 Code of Federal Regulations (CFR) Part 54.4(a) and subject to an AMR in accordance with 10 CFR 54.21(a)(1).

If these structural fire barriers are excluded from the scope of license renewal and not subject to an AMR, the staff requests that the applicant provide justification for the exclusion.

RAI 2.2.4-1 Response Structural fire barriers (walls, ceilings, floors and slabs) are within the scope of license renewal and subject to an aging management review. They are listed within the tables of the associated structures with an intended function "FB". The aging management program for these commodities is the Fire Protection Program.RAI 2.3.2.3-1 Page 498 of the James A. FitzPatrick Nuclear Power Plant (JAFNPP) updated final safety analysis report (UFSAR) states that each of the eleven safety/relief valves [(SRVs)] is equipped with a nitrogen accumulator.

These pneumatic accumulators ensure the ability of the SRVs to depressurize the vessel in the event of a small to intermediate size line break concurrent with a high-pressure coolant injection (HPCI) failure and an interruption of the pneumatic supply to the accumulators.

This provides short term automatic depressurization system SRV capability.

Long term operation of the SRVs is assured with the seismically qualified lines to the accumulators.

LRA Table 2.3.2-3 does not list accumulators as in scope, therefore, the staff requests that the applicant indicate if the above accumulators have been included in scope and identify the LRA Table and subcomponent group that includes the subject component.

Ifthe component is not in scope, please justify the exclusion or submit an AMR for the component.

RAI 2.3.2.3-1 Response These accumulators are included in scope and are reviewed as part of the service, instrument and breathing air system as shown on LRA drawing FM-29A. They are included in Tables 2.3.3-10 and 3.3.2-10 as a component type of tank exposed to an internal environment of gas.Attachment 1 Page 1 of 27 JAFP-07-0021 RAI 2.3.3.5-1 LRA drawing LRA-FB-48A-0 shows the motor driven vertical turbine make up pump (P-3), hydropneumatic tank (TK-4), and associated components as out of scope (i.e., not colored in blue). The staff requests that the applicant verify whether the motor driven vertical turbine make up pump, hydropneumatic tank, and associated components are in 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 excluded from the scope of license renewal and not subject to an AMR, the staff requests that the applicant provide justification for the exclusion.

RAI 2.3.3.5-1 Response The motor driven jockey fire pump (76-P-3) maintains fire system pressure during standby operations.

As shown at coordinate C-3 on drawing LRA-FB-48A, this component is outside the quality class "M" (augmented quality) boundary that defines components required for 10CFR50.48 at JAFNPP. However, the pump and its associated components support standby operation of the fire water system and are being included in the scope of license renewal and subject to aging management review. No changes are required to Table 2.3.3-5 to include these components.

Because the component types of pump casing, piping, valve body, and sight glass exposed to raw water are already included in Table 3.3.2-5 and credit the Fire Water System Program as the aging management program, a change to Table 3.3.2-5 for these component types is not required.

For the hydro pneumatic tank, the following aging management review results are added to Table 3.3.2-5.Component type Tank Intended function Pressure boundary Material Carbon steel Environment Raw water Aging Effect Requiring Management Loss of material Aging Management Program Fire Water System NUREG 1801 Vol. 2 Item VII.G-24 (A-33)Table 1 Item 3.3.1-68 Notes B RAI 2.3.3.5-2 LRA drawing LRA-FB-48A-0 shows the yard fire hydrants to be in scope (i.e., colored in blue).The LRA Table 2.3.3-5, "Fire Protection-Water System Components Subject to Aging Management Review," and Table 3.3.2-5, "Fire Protection-Water System Summary of Aging Management Evaluation," do not list yard fire hydrants for the Fire Protection-Water System.According to JAFNPP commitments to satisfy Appendix A to Branch Technical Position (BTP)Auxiliary and Power Conversion Systems Branch (APCSP) 9.5-1, "Guidelines for Fire Protection for Nuclear Power Plants," May 1, 1976," August 23, 1976, JAFNPP letter dated January 11, 1977, states that: "the condensate storage tanks located outdoors are protected by outside fire hydrants and associated hose houses and equipment." The staff requests that the applicant verify whether the yard fire hydrants are subject to an AMR in accordance with 10 CFR 54.21(a)(1).

If they are excluded from an AMR, the staff requests that the applicant provide justification for the exclusion and address how the aging of those hydrants will be managed for the extended period of operation to ensure providing an effective hose stream Attachment 1 Page 2 of 27 JAFP-07-0021 when required.

Furthermore, fire hydrants are considered passive and long-lived components in accordance with 10 CFR 54.21.RAI 2.3.3.5-2 Response The yard fire hydrants are subject to aging management review as shown on LRA-FB-49A and are included in the component type "valve body" listed in Table 2.3.3-5. The corresponding line item in Table 3.3.2-5 is valve body with material gray cast iron and environment raw water (int).RAI 2.3.3.5-3 LRA drawing LRA-FB-48A-0 shows the sprinkler heads to be in scope (i.e., colored in blue). The LRA Table 2.3.3-5, "Fire Protection-Water System Components Subject to Aging Management Review," and Table 3.3.2-5, "Fire Protection-Water System Summary of Aging Management Evaluation," do not list sprinkler heads for the Fire Protection-Water System. The staff requests that the applicant verify whether the sprinkler heads are subject to an AMR in accordance with 10 CFR 54.21(a)(1).

If they are excluded from an AMR, the staff requests that the applicant provide justification for the exclusion.

RAI 2.3.3.5-3 Response Sprinkler heads are subject to aging management review as shown on LRA-FB-49A and are included in the component type "nozzle" listed in Tables 2.3.3-5 and 3.3.2-5. Materials are carbon steel and copper alloy > 15% Zn.RAI 2.3.3.5-4 LRA drawing LRA-FB-49A-0 shows the east diesel fire pump and Screenwell Building fire suppression system and associated components as out of scope (i.e., not colored in blue). The staff requests that the applicant verify whether the east diesel fire pump and Screenwell Building fire suppression system and associated components are in 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 excluded from the scope of license renewal and not subject to an AMR, the staff requests that the applicant provide justification for the exclusion.

RAI 2.3.3.5-4 Response The east diesel fire pump (76-P-4) is a backup to the main diesel fire pump (76-P-1) and electric fire pump (76-P-2) which supply all normal fire water loads. It is not required to comply with the requirements of 10 CFR 50.48 as described in Technical Requirements Manual (TRM) Section B 3.7.H and is therefore not in scope for license renewal. The screenwell building fire suppression system is shown on LRA-FB-49A at coordinates D1 to GI. This system is highlighted as subject to aging management review with the exception of the components on the discharge of the east diesel fire pump which is not required for 10 CFR 50.48 compliance, and its components are included in LRA Table 3.3.2-5.Attachment 1 Page 3 of 27 JAFP-07-0021 RAI 2.3.3.5-5 Section 4.3.1.3 of the Safety Evaluation (SE) dated August 1, 1979, states that a 30 gpm automatic electric driven centrifugal jockey pump is located in the same room as the electric motor driven fire pump. The jockey pump takes suction from the intake sump to maintain about 150 psig in the fire water system yard loop. The jockey pump and its associated components appear to have fire protection intended functions required for compliance with 10 CFR 50.48 as stated in 10 CFR 54.4. The staff requests that the applicant verify whether the jockey pump and its associated components are in 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 excluded from the scope of license renewal and not subject to an AMR, the staff requests that the applicant provide justification for the exclusion.

RAI 2.3.3.5-5 Response The motor driven jockey fire pump (76-P-3) maintains fire system pressure during standby operations.

As shown at coordinate C-3 on drawing LRA-FB-48A, this component is outside the quality class "M" (augmented quality) boundary that defines components required for 10CFR50.48 at JAFNPP. However, the pump and its associated components support standby operation of the fire water system and are being included in the scope of license renewal and subject to aging management review. Because the component types of pump casing, piping, valve body, and sight glass exposed to raw water are already included in Tables 2.3.3-5 and 3.3.2-5 and credit the Fire Water System Program as the aging management program, a change to the LRA tables for these component types is not required.RAI 2.3.3.5-6 Section 4.3.1.4 of the SE dated August 1, 1979, discusses interor hose stations in plant areas.The staff requests that the applicant to verify whether these interior hose stations and their associated components are in 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 excluded from the scope of license renewal and not subject to an AMR, the staff requests that the applicant provide justification for the exclusion.

RAI 2.3.3.5-6 Response The interior hose stations have intended functions that are required for 10CFR54.4 (a)(3) and are therefore included in the scope of license renewal. These hose stations are included in the structural aging management review in the "Fire hose reels" line item in LRA Tables 2.4-4 and 3.5.2-4, for bulk commodities.

Piping and valve components supplying raw water to the hose reels are included in Tables 2.3.3-5 and 3.3.2-5 and credit the Fire Water System Program as the aging management program. As stated in LRA Section B.1.13.2, the ire hoses on these hose reels are periodically replaced and are therefore not subject to aging management review.This is consistent with NUREG-1 800, Table 2.1-3 which classifies fire hoses as consumables.

Attachment 1 Page 4 of 27 JAFP-07-0021 RAI 2.3.3.5-7 Section 4.3.1.5 of the SE dated August 1, 1979, discusses preaction sprinkler systems provided in the recirculation pumps motor generator set room and in the emergency diesel generator rooms. The LRA does not list preaction sprinkler systems and their associated components provided in the recirculation pumps motor generator set room and in the emergency diesel generator rooms as being in scope and subject to an AIvR. The staff requests that the applicant verify whether the preaction sprinkler systems and their associated components are in the scope of license renewal in accordance with 10 CER 54.4(a) and subject to an AMR in accordance with 10 CFR 54.21 (a)(1). If they are excluded from the scope of license renewal and not subject to an AMR, the staff requests that the applicant provide justification for the exclusion.

RAI 2.3.3.5-7 Response Pre-action sprinkler systems and associated components in the recirculation pumps motor generator set room (LRA-FB-49A, coordinate G-6) and emergency diesel generator rooms (LRA-FB-49A, coordinate F-2) are subject to aging management review with components included in LRA Tables 2.3.3-5 and 3.3.2-5 and highlighted on referenced LRA drawings.RAI 2.3.3.5-8 Section 4.3.1.5 of the SE dated August 1,1979, discusses manual water spray systems in the HPCI pump room and reactor core isolation coolant (RCIC) pump room; in the vicinity of the standby gas treatment (SGT) system charcoal filters, hydrogen seal oil unit, and turbine generator bearing boxes; and in the reactor feed-pump turbine area and piping area. The LRA does not list manual water spray systems provided in HPCI and RCIC pump rooms; in the vicinity of the SGT system charcoal filters, hydrogen seal oil unit, and turbine generator bearing boxes; and in the reactor feed-pump turbine area and piping area as being in scope and subject to an AMR. The staff requests that the applicant verify whether the manual water spray systems and their associated components are in the scope of license renewal in accordance with 10 CFR 54.4(a) and subject to anAMR in accordance with 10 CFR 54.21(a)(1).

If they are excluded from the, scope of license renewal and not subject to an AMR, the staff requests that the applicant provide justification for the exclusion.

RAI 2.3.3.5-8 Response Water spray systems in the HPCI pump rooms (LRA-FB-49A, coordinate F-7), RCIC pump rooms (LRA-FB-49A, coordinate F-7), SGT system charcoal filters (LRA-FM-49A, coordinates F-7), hydrogen seal oil unit (LRA-FB-49A, coordinate E-3), turbine generator bearing boxes (LRA-FB-49A, coordinate G-5), and reactor feed pump turbine and piping area (LRA-FB-49A, coordinates D-3, F-3) are subject to aging management review with components included in LRA Tables 2.3.3-5 and 3.3.2-5 and highlighted on referenced LRA drawings.RAI .2.3.3.5-9 Section 4.5 of the SE dated August 1, 1979, discusses food drains provided in all plant areas protected with a fixed water fire suppression system. The curbs/dikes are provided for liquid tanks in the diesel fire pump area, the dirty oil storage rooms, and main oil sump room to contain oil and fire water. The LRA does not list flood drains and curbs/dikes as being in scope and Attachment 1 Page 5 of 27 JAFP-07-0021 subject to an AMR. The staff requests that the applicant verify whether the flood drains and curbs/dikes are in 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 excluded from the scope of license renewal and not subject to an AMR, the staff requests that the applicant provide justification for the exclusion.

RAI 2.3.3.5-9 Response Drain system components provided for protection of equipment from fire suppression water are in scope and subject to aging management review. They are part of the radwaste and plant drains system described in Section 2.3.3.12 of the LRA. The components subject to aging management review in this system are described in LRA Tables 2.3.3-12 and 3.3.2-12. "Flood curbs" are structural commodities that are in scope and subject to aging management review and included in LRA Tables 2.4-4 and 3.5.2-4, for bulk commodities.

RAI 2.3.3.5-10 Section 4.11 of the SE dated August 1, 1979, discusses the installation offire resistance coating on exposed structural steel in the plant areas where the failure of exposed structural steel supporting fire barriers (floors, walls, and ceilings) could impair the safe-shutdown capability of the plant. These areas include the reactor building, turbine building, control building, diesel generator building, and others. The LRA does not list three-hour rated fire resistance coating for exposed structural steel as being in scope and subject to an AIVR. The staff requests that the applicant verify whether the fire resistance coating for structural steel is in 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 structural fire resistance coating is excluded from the scope of license renewal and not subject to an AMR, the staff requests that the applicant provide justification for the exclusion.

RAI 2.3.3.5-10 Response Flame retardant coatings are in scope and subject to aging management review and are included in the line item "Fire proofing" in LRA Tables 2.4-4 and 3.5.2-4, for bulk commodities.

RAI 2.3.3.5-11 JAFNNP is required to meet Appendix A to BTP APCSP 9.5-1. According to JAFNPP commitments to satisfy Appendix A to BTP APCSP 9.5-1, JAFNPP letter dated January 11, 1977, states that: "The Emergency Diesel Generator A and C combined ventilation air intake is located approximately 40 ft from the Station Reserve Transformer, T-3. This air intake is approximately 10 ft above the ground. It is not practicable to seal this opening 4ith a 3 hr fire barrier or by a combination of opening seals and water spray.The Power Authority does not consider it necessary to provide a 3 hr fire barrier between the ventilation opening and the transformer for the follovdng reasons: Attachment 1 Page 6 of 27 JAFP-07-0021

1) The transformer is protected by an automatic water spray deluge system in accordance with NFPA 13." The staff requests that the applicant verify whether the automatic water deluge system for the Station Reserve Transformer, T-3 is in 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 the automatic water deluge system is excluded from the scope of license renewal and not subject to an AMR, the staff requests that the applicant provide justification for the exclusion.

RAI 2.3.3.5-11 Response As shown on LRA-FB-49A at location E-3, the automatic water deluge system protecting station reserve transformer (T-3) is in scope and subject to aging management review and is included in LRA Tables 2.3.3.5 and 3.3.2-5.RAI 2.3.3.6-1 LRA Section 2.3.3.6 describes the CO 2 fire suppression system as being in the scope of the license renewal and subject to an AMR. The aging management program (AMP) for the C02 fire suppression system does not appear in LRA Section B. 1.13, "Fire Protection Program." The NUREG-1801, GALL Report, Revision 1,Section XI.M26, "Fire Protection," describes the requirements for aging management of the C02 fire suppression system. It requires that an AMP be established to evaluate the periodic visual inspection and function test be performed at least once every six months to examine the signs of degradation of the C02 fire suppression system. Material conditions that may affect the performance of the system, such as corrosion, mechanical damage, or damage to dampers, are observed during these tests. The staff requests that the applicant describe the AMP and operating experience for the C02 fire suppression system in LRA Section B.1.13.RAI 2.3.3.6-1 Response Although the Fire Protection Program is credited for the management of C02 fire suppression system component aging effects in Table 3.3.2-6, the C02 fire suppression system was inadvertently omitted from the description of the Fire Protection Program. The program description of LRA Section B.1.13.1 is hereby revised to include the following sentence.The Fire Protection Program also includes management of the aging effects on the intended function of the C02 fire suppression system.The following exception to NUREG-1801 is also added to Section B.1.13.1: Attributes Affected Exception 3. Parameters The functional test of the 002 fire suppression system Monitored

/ Inspected is performed on a 24-month basis as listed in the 4. Detection of Aging current licensing basis for JAF. This frequency is Effects sufficient to ensure system availability and operability based on station operating history and to ensure that aging effects will be properly managed through the period of extended operation. (Note 1)Attachment 1 Page 7 of 27 JAFP-07-0021 Exception Note 1. The NRC Staff, as documented in the license renewal SER for Oyster Creek, has accepted the position that, in the absence of age-related degradation adversely affecting system operation and provided that visual inspections of component external surfaces are performed every six months, the periodicity specified in the current licensing basis for functional testing of the CO 2 system is sufficient to ensure system availability and operability.

Operating experience for the C02 fire suppression system is already described in LRA Section B.1.13 in the following statements.

QA audits and surveillances in 2002 and 2003 revealed that the material condition of system equipment was good and met licensing requirements.

The audits and surveillances revealed no issues or findings that could impact effectiveness of the program to manage aging effects for fire protection components.

In March 2005, NRC completed a triennial fire protection team inspection to assess whether the plant has implemented an adequate fire protection program and that post-fire safe shutdown capabilities have been established and are being properly maintained.

Results confirmed that plant personnel were maintaining the fire protection systems in accordance with their fire protection program and identifying program deficiencies and implementing appropriate corrective actions.RAI 2.3.3.6-2 LRA Table 2.3.3-6, "Fire Protection-CO 2 Components Subject to Aging Management Review," and Table 3.3.2-6, "Fire Protection-CO 2 Components Summary of Aging Management Evaluation," exclude several types of C02 fire suppression system components that appear in the LRA drawing LRA-FB-56A-0 colored in purple. These components are listed below.strainer siren body strainer housing pipe supports filter housing couplings heater housing odorizer orifice threaded connections pneumatic actuators For each, determine whether the component should be included in Tables 2.3.3-6 and 3.3.2.6, and if not, justify the exclusion.

RAI 2.3.3.6-2 Response Pneumatic actuators are active components and therefore not subject to aging management review.Pipe supports are subject to aging management review. They are included in LRA Table 2.4-4 with AMR results provided in LRA Table 3.5.2-4 under "component and piping supports." There are no components of the types strainer, strainer housing, filter housing, heater housing, siren body, or odorizer in the Fire Protection--C02 system nor are they shown on LRA drawing Attachment 1 Page 8 of 27 JAFP-07-0021 LRA-FB-56A-0.

Component types orifice, coupling, and threaded connection which contain C02 are subject to aging management review and are included in the component type "piping" in LRA Tables 2.3.3-6 and 3.3.2.6.RAI 2.3.3.6-3 According to JAFNPP commitments to satisfy Appendix A to BTP APCSP 9.5-1, JAFNPP letter dated January 11, 1977, states that: 'the plant computer room is located within a wire fence area inside the relay room... The relay room (including computer room) is protected by a total flooding C0 2 system with outside backup by a water hose station and portable C02 extinguisher." UFSAR Section 9.8.3.11 states that: "Halon is used forfire protection in the Emergency and Plant Information Computer (EPIC) Room where it is not desirable to use a water spray or a sprinkler system." The staff requests that the applicant verify whether the flooding C02 fire suppression system or Halon fire suppression system in the EPIC room is in 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 the CO 2 or Halon fire suppression system is excluded from the scope of license renewal and not subject to an AMR, the staff requests that the applicant to provide justification for the exclusion.

RAI 2.3.3.6-3 Response The emergency and plant information computer (EPIC) system is not safety-related nor is it credited to support a safe shutdown in any fire scenarios to demonstrate compliance with 10 CFR 50.48. Therefore, the Halon system in the EPIC room is not required to support 10 CFR 50.48 and is not in the scope of license renewal nor subject to AMR.As discussed in LRA Section 2.3.3.6 and shown in Table 2.3.3-6, the total flooding C02 fire suppression system for the relay room is in the scope of license renewal. Results of the AMR for the components in this portion of the system are listed in LRA Table 3.3.2-6 and shown on LRA drawing LRA-FB-56A.

RAI 2.5-1 In Section 2.5 (Page 2.5-2) of the LRA, the switchyard bus is included in the list of components/commodity groups subject to AMR. However, the switchyard bus is not shown in the LRA, Figure 2.5-1, "SBO Offsite Power Scoping Diagram." Please provide details of the switchyard bus which is included in the scope subject to AMR.RAI 2.5-1 Response The switchyard bus that is in scope and subject to aging management eview are the short sections that provide connections to the 115kV underground oil-filled transmission cables at reserve station service transformer (T2) and switchyard breaker (10022). Also included are the short sections that provide connections to the overhead transmission conductors at reserve station service transformer (T3) and switchyard breaker (10012). LRA Figure 2.5-1 is updated as shown in this response.Attachment 1 Page 9 of 27 JAFP-07-0021 115kV Switchyard Non Segregated Phase Bus 115kV Underground Cable 1 5kV Transmission Lines Switchyard Bus Ap I Tra Reserve Station Service Transformer T2 x winding y winding isformer Yard Reserve Station Service Transformer T3 F x winding Fyywindin~g Switchgear Rooms 4kV Bu: Non ý4kV Bus 10600 Safety 4kV Bus 10500 Safety Figure 2.5-1 SBO Offsite Power Scoping Diagram Attachment 1 Page 10 of 27 JAFP-07-0021 RAI 3.1.2-2A The applicant implemented AMP B.1.7, "BWR Vessel Internals," for managing the aging effects due to loss of preload and cracking in these bolts. AMP B.1.7 in turn invokes the inspection guidelines that are specified in the BWRVIP-25 report, "BWR Core Plate Inspection and Flaw Evaluation Guidelines." Table 3.1.2-2 of the Boiling Water Reactor Vessel and Internals Project (BWRVIP)-25 report recommends that if wedges are not-installed, the core support rim bolts should be inspected for cracks using enhanced visual testing (EVT-1) from below the core plate or ultrasonic testing (UT) from above the core plate if an effective UT technique is developed.

Since wedges are not currently installed at JAFNPP, the staff requests that the applicant provide information regarding the type of inspection methods, inspection frequency and the results of the inspections that have been performed thus far on core support rim bolts. If the applicant does not plan to install wedges, it should provide information regarding the accessibility for performing the inspections, type of inspections including UT technique, and inspection frequency that will be used to monitor the aging degradation in the core support rim bolts during the license renewal period.RAI 3.1.2-2A Response During RO1 1 in December 1994, twenty core plate hold-down bolts were examined by visual inspection (VT-i). The bolts were examined from the top side of the core plate. All examined bolts showed that the weld keeper used as a nut lock remained fillet welded to the top of the bolt. The pertinent plant drawing shows that this is typical for all 72 bolt locations.

During R013 in October-November 1998, all 72 core plate hold-down bolts were examined by visual inspection (VT-3) from the top side of the core plate. This inspection again showed the nut lock welded to the top of each bolt.As described in the response to RAI 4.7.3.2-1 below, JAFNPP will perform one of the following.

1. Install core plate wedges prior to the period of extended operation, or 2. Complete a plant-specific analysis to determine acceptance criteria for continued inspection of core plate rim hold down bolting in accordance with BWRVIP-25 and submit the inspection plan to the NRC two years prior to the period of extended operation for NRC review and approval, or 3. Perform inspection of core plate rim hold down bolts in accordance with ASME Code Section XI or in accordance with an NRC-approved version of BWRVIP-25.

If Option 2 is selected, the analysis to determine acceptance criteria will address the information requested in RAIs 3.1.2-2A and 4.7.3.2-1.

License renewal commitment 23 specifies this commitment.

RAI 3.1.2-2B (Editorial)

Table 3-2 of the BWRVIP-25 report addresses inspection strategy for the core plate hold-down bolts. However, in Table 3.1.2-2 of the LRA, the applicant identifies them as core support rim bolts. To maintain consistency in nomenclature, the staff requests that applicant revise Table.3.1.2-2 of the LRA to include core plate hold-down bolts in lieu of core support rim bolts.Attachment 1 Page 11 of 27 JAFP-07-0021 RAI 3.11.2-2B Response The "core support rim bolts" identified in Tables 2.3.1-2 and 3.1.2-2 of the LRA are equivalent to the "core plate hold-down bolts". Tables 2.3.1-2 and 3.1.2-2 are revised to replace the component description of "core support rim bolts" with "core plate hold-down bolts". LRA Section 4.7.3.2 and Appendix C use the term "core plate hold-down bolts" and require no change.RAI 3.5.2-1 In Table 3.5.2-1 under Structure and/or Component or Commodity "Drywell shell," "Drywell to vent system," and "Torus shell," JAFNPP Containment Inservice Inspection (CII) and Containment Leak Rate programs are credited to manage loss of material due to general, pitting, and crevice corrosion.

The staff requests the applicant to verify that these programs include the aging effects on both accessible and inaccessible areas.RAI 3.5.2-1 Response As shown in the license renewal application (LRA) Table 3.5.2-1, loss of material for drywell shell, drywell to torus vent system and torus shell is managed by aging management programs (AMP) B.1.16.1, "Containment Inservice Inspection (CII)" and B.1.8, "Containment Leak Rate".These programs manage the effects of aging on both accessible and inaccessible areas when they become accessible, when inspection results of similar component show significant degradation, or when operating experience warrants such inspections.

As stated in LRA Section B.16.1 the CII Program invokes 10 CFR 50.55a(b)(2)(ix) which specifies additional requirements for inaccessible areas. It states that the licensee is to evaluate the acceptability of inaccessible areas when conditions exist in accessible areas that could indicate the presence of or result in degradation to such inaccessible areas. As stated in LRA Section B.1.8 the Containment Leak Rate Program invokes the 10 CFR 50, Appendix J Program described in NUREG-1801,Section XI.S4. This program monitors leakage rates through containment shells; containment liners; and associated welds, penetrations, fittings, and other access openings.

This monitoring addresses leakage through inaccessible areas such as the embedded containment ordrywell shell.RAI 3.5.2-2 In Table 3.5.2-1 under Structure and/or Component or Commodity "Drywell shell," and "Torus shell," JAFNPP CII Program is credited to manage the loss of material due to general, pitting, and crevice corrosion.

Operating experience in the AMP stated "Results of the CII general visual walkdown of primary containment during RO15 (2002) revealed minor areas of peeling paint and rust scale." The staff requests the applicant to provide the root cause and any preventive actions taken to alleviate the instances of peeling paint and rust scale in primary containment.

RAI 3.5.2-2 Response During the Refueling Outages in 2002, 2004 and 2006 a general visual walkdown of the Primary Containment for IWE was performed for the various elevations from 256'-6" to 331'-0". The walkdowns revealed surface areas minor in size which were found to have degraded conditions concerning cracking/peeling paint and/or evidence of rust scale. In 2002, the degraded Attachment 1 Page 12 of 27 JAFP-07-0021 conditions were identified in Condition Report CR-JAF-2003-02527 and maintenance activities were completed per Work Order JF-030619900.

The cracking/peeling paint is apparently caused by improper cleaning and preparation of the steel substrate, and the coating delaminating from the surface. Identified areas of concern have been determined to be minor surface degradations and have been repaired.

JAF will continue to perform a general visual walkdown of Primary Containment in accordance with the IWE during refueling outages. Any degraded conditions identified will be evaluated in-the JAF corrective action program for appropriate repair as required.RAI 3.5.2-3 In Table 3.5.2-1 under Structure and/or Component or Commodity "Drywell shell," JAFNPP CII and Containment Leak Rate Programs are credited to manage the loss of material due to general, pitting, and crevice corrosion.

However, it was unclear to the staff how and when inspections were performed to verify that there has been no observed leakage causing moisture in the vicinity of the sand cushion at JAFNPP and no moisture has been detected or is suspected on the inaccessible areas of the drywell shell which would result in corrosion and wall thinning.

If conditions exist, the staff requests the applicant to address proposed license renewal interim staff guidance LR-ISG-2006-01, "Plant Specific Aging Management Program for Inaccessible Areas of Boiling Water Reactor Mark 1 Steel Containment Drywell Shell," which was published in the Federal, Register on May 9, 2006. Also, the staff requests the applicant to provide significant findings during the implementation of, and subsequent examinations to GL 87-05, "Request for Additional Information-Assessment of Licensee Measures to Mitigate And/Or Identify Potential Degradation of Mark I Drywells." RAI 3.5.2-3 Response Purpose For license renewal, the NRC evaluates the potential for corrosion of the Mark I steel containment drywell shell. This issue was previously the subject of generic NRC communications.

Specifically, Generic Letter (GL) 87-05 documented potential degradation of Mark I drywells due to corrosion.

The following provides additional information on the J. A. FitzPatrick Nuclear Power Plant drywell shell relative to recent industry experience in this area.Back~qround In 1980, Oyster Creek Station personnel observed water coming from lines that drain water from the annulus region between the drywell wall and the surrounding concrete and the sand cushion region. The water source was initially identified in 1983 as coming from the Drywell-Refueling Cavity bellows drain line gasket. After performing ultrasonic thickness measurements in 1986, Oyster Creek Station reported that corrosion and material loss had occurred to the drywell shell in the area of the sand-cushion.

This finding led to the issuance of NRC Information Notice 86-99,"Degradation of Steel Containments," Generic Letter 87-05, "Request for Additional Information-Assessment of Licensee Measures to Mitigate and/or Identify Potential Degradation of Mark I Drywells," and Information Notice 86-99 Supplement 1.The purpose of GL 87-05 was "...to initiate the collection of information of the licensee's current and proposed action to assure the degradation of the drywell shell plates adjacent to the sand-cushion has not occurred and to determine if augmented inspections above and beyond those planned by the licensee are necessary." Attachment 1 Page 13 of 27 JAFP-07-0021 In 1995, subsequent to the GL responses, the staff approved the use of ASME Section XI, Subsection IWE (Requirements for Class MC and Metallic Liners of Class CC Components of Light-Water Cooled Plants) which exempts from examination, in accordance with Subparagraph IWE-1220(b), "embedded or inaccessible portions of containment vessels, parts, and appurtenances that met the requirements of the original Construction Code..." However, Paragraph IWE-1240 establishes criteria for determining the need for augmented examinations.

JAF Primary Containment Desiqn JAF employs a low-leakage pressure suppression system which houses the reactor vessel, the reactor coolant recirculation loops, and other branch connections of the reactor primary system.The Primary Containment is of the pressure suppression type and consists of the drywell, the torus containing a large volume of water, the connecting vent system between the drywell and the torus, isolation valves, vacuum relief system, and the Residual Heat Removal (RHR) subsystem for containment cooling.The drywell is an inverted light bulb-shaped carbon steel primary containment structure with a spherical lower portion, 65 feet in diameter, and a cylindrical upper portion 30 feet 2 inches in diameter.

The overall height is approximately 112 feet 3 / inches. The drywell is enclosed in reinforced concrete for shielding purposes and to provide additional resistance to deformation and buckling in areas where the concrete backs up to the steel shell. Shielding above the drywell is provided by removable, segmented, reinforced concrete shield plugs located on the reactor building refuel floor. The reinforced concrete drywell floor contains the drywell floor drain and equipment drain sumps and also supports the reactor pedestal.The design, fabrication, inspection, and testing of the drywell complies with requirements of the ASME Boiler & Pressure Vessel Code,Section III, Subsection B, Requirements for Class B Vessels, 1968 Edition, which pertain to containment vessels for nuclear power stations.Drywell Shell Exterior The sand cushion at the base of the drywell is designed to provide a smooth transition to reduce thermal and mechanical discontinuities.

The sand provides lateral support to the drywell in this region. The sand cushion area is drained to protect the exterior surface of the drywell shell at the sand cushion interface from water that might inadvertently enter the 2" air gap between the drywell shell and the concrete wall around the drywell.Two inspections were required per NRC Generic Letter 87-05 prior to start-up from the 1988 Refuel Outage. The first inspection involved four (4) 2" diameter sand cushion drain lines and four (4) 2" diameter air gap drain lines using a flexible boroscope.

The inspections were to determine that all drain lines were open and functioning as designed.

All drain lines were open and fully functional with the exception of one (1) of the air gap drain lines, which was plugged at the drywell end, resulting in no flow. JAF determined that only one out of the four air gap drain lines is required to perform the function that they were designed for, the draining of condensates which may form in the air gap. The second inspection included the six (6) refueling bellows leakage drain lines. Five of the six refueling bellows leakage drain lines were inspected through inspection ports and found to be operable.

An inspection port was not installed in the sixth line because of the line's inaccessibility.

JAF also examined the air gap with a boroscope through the drain lines and did not find any evidence of moisture in the air gap or corrosion of the drywell shell. It should be noted that the bellows drain lines are welded in place and have no gaskets that can leak as Attachment 1 Page 14 of 27 JAFP-07-0021 existed at the Oyster Creek Station.As documented in J. A. FitzPatrick Nuclear Power Plant Response to Generic Letter 87-05 to the U. S. Nuclear Regulatory Commission, dated May 11, 1987, Docket 50-333, the sand cushion for JAF is covered with stainless steel plates and an adhesive seal to prevent in-leakage.

Drains are provided immediately above these plates and also at the bottom of the sand cushion. "Because of this design arrangement, no ultrasonic thickness measurements were performed for the drywell shell plates adjacent to the sand cushion. As stated inthe NYPA memo, all drain connections are welded; therefore, there are no gasket inspections or maintenance required." With regard to the inner surface of the drywell, the gap seal between the concrete floor (Elevation 256'-6") and the drywell shell is inspected for functionality.

There have been no discemible signs of degradation in the sealant material or in the concrete and steel surfaces in the area of the seal.To ensure the drywell shell exterior remains dry during refueling evolutions, the drywell to reactor building bellows assembly separates the refueling cavity filled with water from the exterior surface of the drywell shell. Any leakage through the bellows assembly is directed to a drain system ((inner bellows to the Drywell Equipment Drain Sump, outer bellows to the "B" Condensate Storage Tank), where two lines are each equipped with a flow indicator/switch that will alarm in the Control Room in the event of a bellows failure. A PM -"Test 19FIS-61 prior to initial refuel cavity flood-up" is performed every outage to verify the indicator/switch is functional and the Control Room annunciator responds when water is added to the line. In addition, a PM- Functional Test of 19FIS-62 is performed every two years to verify the indicator/switch and associated Control Room annunciator are functional.

Drywell Shell Interior The majority of the upper portion of the drywell shell interior surfaces is accessible for inspection, except the lower portion of the drywell where it is covered by the concrete drywell floor. This inaccessible area of the drywell is exempt from examination per the IWE program.A general visual examination (IWE) of the interior of the drywell coating from Elevation 331'-0" (top of the Bio-Shield Wall) to Elevation 256'-6" (bottom of the drywell) is performed every refueling outage. In general, the overall coating of the steel surface is in good condition.

There are small areas (less than 2 square feet in size), of flaking and peeled paint from various elevations, and the wall section behind the "A' and "B" Cooling Filters shows signs of rust staining on the coating from elevation 268'-0" to elevation 256'-6". The rust color staining is from the condensation forming on the cooling lines to the filters. The piping behind the Cooling "A" and "B" Filters were cleaned and two of the pipe lines were painted.The JAF primary containment system is inerted with nitrogen gas during normal power operations so that oxygen levels are maintained at less than 4%. Inerting with nitrogen provides an atmosphere that is not conducive to corrosion of containment interior surfaces.

With such a low oxygen level the oxidation of the steel is diminished.

OperatinQ Experience and Actions Taken to Prevent DrVwell Corrosion There has been no observed active leakage causing moisture in the vicinity of the sand cushion drain line at JAF as monitored by IWE general visual examination of the exterior of the torus and torus room. No moisture has been detected or suspected on the inaccessible areas of the drywell shell. Any leakage through the refueling bellows assembly is directed to a drain system (inner Attachment 1 Page 15 of 27 JAFP-07-0021 bellows to the Drywell Equipment Drain Sump, outer bellows to the "B" Condensate Storage Tank). Therefore, no additional components have been identified that require aging management review as a source of moisture that may affect the drywell shell in the lower region.* In 1988, JAF examined the air gap through the drain lines using fiber optic cables and did not have any evidence of moisture potentially causing corrosion of the drywell shell (Reference NYPA Memorandum No. JTS-88-0875, from V. Walz to W. Femandez, dated November 1, 1988). JAF plans to perform an additional examination in 2007 (Reference maintenance work order WO # [[::JAF-07-14863|JAF-07-14863]].

If any evidence of moisture is identified JAF will determine additional inspection activities, as appropriate.

  • JAF monitors refueling bellows leakage drain lines during every refueling outage. Flow indicator/switches 19FIS-61 and 19FIS-62 were successfully last tested in 2006. The flow indicators/switches are on a two year PM frequency.
  • Drywell interior surfaces are examined for degradation every refueling outage in accordance with the JAF IWE Program. A general visual examination has been performed every refueling outage looking at the steel and concrete surfaces for shrinkage cracks in the concrete, cracking and peeling coating, and discoloration of the surface coating (bleed through, staining).

There were areas of minor corrosion bleed though the coating (less than 4 square feet) and staining (less than 50 square feet) caused by condensation from the "A" and "B" Cooling filter lines. The areas of peeling and flaking paint are less than 2 square feet areas. Engineering evaluated the minor surface condition at various locations and were found to be acceptable.

The minor degraded areas are monitored every refueling outage.* The drywell shell to floor caulked seal is inspected every refueling outage. A general visual examination is performed looking for cracking, peeling, delaminating or separation of the seal, discoloration in the caulking material, and flexibility of the caulking.

The caulk seal has not been removed or replaced.Conclusion JAF has effectively addressed the issue of drywell shell corrosion through actions taken in response to GL 87-05, as well as additional actions subsequent to the response to GL 87-05.Drywell interior surfaces and shell to floor joint examinations are conducted every refueling outage.The above described ongoing actions to prevent degradation of the drywell shell, will provide continuing reasonable assurance of satisfactory drywell shell condition through the period of extended operation.

Attachment 1 Page 16 of 27 JAFP-07-0021 PRIMARY CONTAINMENT DETAIL Attachment 1 Page 17 of 27 JAFP-07-0021 DRYWELL 2" AIR SPACE K 2, DRAIN (AJR GAP) 7//(2VER SANA CUSHION)C.," ....EL. 256V-6"'SIN CUSHISOON.

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RAI 3.5.2-4 In Table 3.5.2-1 under Structure and/or Component or Commodity "Drywell to torus vent system," and "Drywell to torus vent line bellows," JAFNPP CII and Containment Leak Rate programs are credited to manage loss of material due to general, pitting, crevice corrosion, and cracking.

The vent system as well as the vent line bellows may be inaccessible and likely to be subject to corrosion (see IN 92-20). The staff requests the applicant to provide operating experience and information on how the AMPs will manage aging effects of these components through the period of extended operation.

RAI 3.5.2-4 Response The drywell to torus vent system and drywell to torus line bellows are accessible for inspection.

As shown in the license renewal application (LRA) Table 3.5.2-1, cracking of stainless steel bellows and loss of material (due to corrosion) of carbon steel drywell to torus vent system are managed by aging management programs (AMP) B. 1.16.1, "Containment Inservice Inspection (CII)" and B.1.8, "Containment Leak Rate". These programs are the same as those identified in GALL for managing aging effects of these components.

Operating experience review at JAFNPP found no evidence of degradation related to general, pitting and crevice corrosion, and cracking of the "Drywell to torus vent system," and "Drywell to torus vent line bellows".RAI 3.5.2-5 In Table 3.5.2-1 under Structure and/or Component or Commodity "Torus shell," JAFNPP CII and Containment Leak Rate programs are credited to manage loss of material due to general, pitting, crevice corrosion.

According to NRC Information Notice 2006-01, "Torus Cracking in a BWR Mark I Containment," which was published on January 12, 2006, the most likely cause of through-wall torus crack was the cyclic loading due to condensation oscillation during HPCI operation.

In order for the AMPs to properly manage aging effect of this structure, the staff requests the applicant to include cracking as an aging effect requiring management.

Also, the staff requests the applicant to provide information on how other areas of the torus that are susceptible to cracking and/or pitting corrosion are managed in order to provide reasonable assurance that the torus will function properly through the period of extended operation.

RAI 3.5.2-5 Response In reference to IN 2006-01, the cause of the torus crack was the cyclic loading resulting from a design flaw, specifically the turbine exhaust pipe had no sparger, such that during HPCI operation hydrodynamic loading was imposed on the torus. Since the flaw resulted from inadequate design rather than aging effect, an aging management program would not be appropriate corrective action. The corrective action for the inadequate design was a design change which included installing a sparger on the exhaust pipe. The other areas of the torus are not susceptible to cracking and areas susceptible to pitting corrosion are included in the aging management programs shown in Table 3.5.2-1. The Containment Inservice Inspection (CII)Program manages loss of material through visual inspections as described in LRA Section B.16.1.Attachment 1 Page 20 of 27 JAFP-07-0021 RAI 3.5.2-6 In Table 3.5.2-1 under Structure and/or Component or Commodity "Drywell shell," and 'Torus shell," JAFNPP referenced no time-limited aging analysis (TLAA). An absence of TLAA related to drywell and torus corrosion indicates that both of these containment components have not experienced degradation that requires such an analysis.

Please explain the condition of these two components to justify that a TLAA is not required for either of these components.

RAI 3.5.2-6 Response The absence of a TLAA related to drywell and torus corrosion does not indicate that these components have not experienced corrosion.

The lack of a TLAA indicates that no analysis exists that meets the definition of TLAA in 10 CFR 54.3 and that the original design required no time-limited analysis.

Corrosion has, in fact, been observed for the materials and environments associated with the drywell and torus. As indicated in LRA Table 3.5.2-1, the Containment Inservice Inspection (CII) and Containment Leak Rate programs manage loss of material, which is an aging effect caused by corrosion.

These programs are the same as those identified in NUREG-1801 for managing aging effects of these components.

In addition, as shovw in Table 3.5.2-1 the torus shell references TLAA -metal fatigue. LRA Section 4.6 discusses the evaluation of metal fatigue for the torus and attached piping. This is the only time-limited aging analysis associated with the primary containment.

RAI 4.2.2-1 Please discuss whether the 54 effective full-power years (EFPY) Pressure-Temperature (P-T)limit curve bases summarized in LRA Table 4.2-3 take into consideration the JAFNPP power uprate conditions.

RAI 4.2.2-1 Response The RTNDT values projected in LRA Table 4.2-3 are based on fluence values of 0.18 x 1019 n/cm2 (e > 1MeV) for the lower shell and 0.22 x 1019 n/cm2 (e > 1MeV) for the lower intermediate shell. These fluence values included the uprate to 2536 Megawatts thermal at the end of Cycle 12.RAI 4.2.2-2 The staff does not require the P-T limit curves for the extended period of operation to be submitted as part of the applicant's LRA for this TLAA. However, the staff does require NRC approval of the P-T limit curves for the extended period of operation prior to the expiration of the facility's current P-T limit curves for 32 EFPY. Please state when you intend to submit P-T limit curves for NRC approval for the extended licensed period of operation (54 EFPY).RAI 4.2.2-2 Response In accordance with 10 CFR Part 50.59 (c)(2), Part 50.60, and Appendix G, JAFNPP will submit P-T curves for use past 32 EFPY prior to reaching 32 EFPY.Attachment 1 Page 21 of 27 JAFP-07-0021 RAI 4.2.3-1 In reference to LRA Table 4.2-1, the applicant is requested to clarify whether any other surveillance capsule data is available.

If so, provide this information and address how this additional data affects your response to RAI 4.2.2-1.RAI 4.2.3-1 Response JAFNPP has withdrawn and analyzed two surveillance capsules (GE-NE-B1100732-01, Revision 1, February, 1998, Plant Fitzpatrick RPV Surveillance materials Testing and Analysis of 1200 Capsule at 13.4 EFPY).With regards to the reactor vessel plate material, this has provided two data sets showing the changes in CvUSE and RTNDT. However, as the observed changes are less than the Regulatory Guide 1.99 projected changes, this report has used Regulatory Guide 1.99 Position 1 and conservatively not reduced the projections based on surveillance data.With regards to the reactor vessel weld material, there are no surveillance data sets. This is because the initial CvUSE and RTNDT for the weld material are not known, and consequently the decrease from the original value cannot be calculated.

Consequently, this report has also used Regulatory Guide 1.99 Position 1 for the weld material evaluations.

The two capsules were withdrawn at 5.98 EFPY (1985) and 13.4 EFPY (1996). Both were withdrawn prior to the power uprate. However, the fluence projections to 32 EFPY based on these capsules was adjusted to account for the power uprate. So there is no adjustment to the answer to RAI 4.2.2-1.RAI 4.2.5-1 The NRC staff requires that a request for relief from the American Society of Mechanical Engineer Boiler and Pressure Vessel Code (ASME Code) reactor vessel (RV) circumferential shell weld examination requirements be submitted prior to the beginning of the extended period of operation.

Please state whether you intend to apply for relief from the ASME Code RV circumferential weld examination requirements for the extended licensed period of operation.

State when you plan to submit this relief request.RAI 4.2.5-1 Response Relief requests are tied to the ASME Section Xl Inservice Inspection program 10-year inspection intervals.

In accordance with the requirements of ASME Section XI, JAFNPP will submit a reactor vessel circumferential weld relief request for each 10-year interval in the period of extended operation prior to the beginning of the interval (or prior to the end of the preceding interval).

RAI 4.2.5-2 In the July 28, 1998 SE for the BWRVIP-05 report, the NRC staff concluded that examination of the RV circumferential shell welds would need to be performed if the corresponding volumetric examinations of the RV axial shell welds revealed the presence of an age-related degradation Attachment 1 Page 22 of 27 JAFP-07-0021 mechanism.

Confirm whether or not previous volumetric examinations of the RV axial shell welds at JAFNPP have shown any indication of cracking or other age-related degradation mechanisms in the welds.RAI 4.2.5-2 Response No unacceptable inservice examination indications have been found on reactor Vessel welds (circumferential or axial) at JAFNPP.RAI 4.2.5-3 The BWRVIP-05 report does not use a margin term for calculations of surface mean RTNDT for RV circumferential welds. Please clarify the inclusion of a margin term in Table 4.2-4 and in section 4.2.5.RAI 4.2.5-3 Response Note that all the margin entries in Tables 4.2-4 and 4.2-5 are zero, and are therefore consistent with the BWRVIP-05 SER. The margin line in Tables 4.2-4 and 4.2-5 were intended to show that the margin called for by RG 1.99 when calculating RTNDT are set to zero here, clearly showing why these RTNDT values are different from the RG 1.99 compliant values calculated in Table 4.2-3.RAI 4.2.6-1 Section 4.2.6 of the JAFNPP LRA states that the mean RTNDT value for the limiting RV axial shell weld at the end of the extended period of operation (54 EFPY) is significantly less than the NRC limiting plant-specific mean RTNDT value established in the staff's March 7, 2000, supplement to the final SE for the BWRVIP-74 report. Therefore, the JAFNPP axial weld failure probability is well below the acceptable limit of 5 x 10.6 per reactor-year.

However, the limiting axial weld failure probability calculated by the NRC is based on the assumption that "essentially 100 percent" (i.e., greater than 90 percent) examination coverage of all RV axial welds can be achieved in accordance with ASME Code,Section XI requirements.

State whether your inservice inspection examinations achieved "essentially 100 percent" (i.e., greater than 90 percent) overall examination coverage for the RV axial welds. If they did not, reference the NRC staff's Safety Evaluation Report granting relief for limited scope axial weld examination coverage for the current licensed operating period. If less than 90 percent overall examination coverage was achieved for the RV axial welds, revise this TLAA to account for the effects of the limited scope examination coverage.RAI 4.2.6-1 Response Due to various obstructions within the reactor vessel, JAPNPP has not been able to inspect"essentially 100%" of the reactor vessel beltline axial welds. Evaluation of the JAFNPP reactor vessel inspection records shows that approximately 88% of the axial welds in the beltline region were inspected (83% of the axial welds total). Although the actual coverage is less than 90%, the actual coverage obtained should identify any pattern of degradation, particularly in the beltline region. The NRC granted a relief request for less than 90% coverage (refer to NRC Attachment 1 Page 23 of 27 JAFP-07-0021 letter R. J. Laufer to M. R. Kansler, Relief Request No.30 (TAC No. MC0293), dated July 21, 2004).The effect of this reduced inspection (2% of the beltline axial welds) on the weld failure probability would be small, but JAFNPP has not attempted to quantify that effect. Table 4.2-4 of the LRA shows a large margin between the 84.7 OF mean adjusted reference temperature for JAFNPP versus the 128.5 OF mean adjusted reference temperatures for the CEOG plant used in the NRC SER for BWRVIP-05 to determine weld failure probability.

The 2% of uninspected weld is unlikely to offset this large margin.RAI 4.7.3.2-1 Section 4.7.3.2 of the JAFNPP LRA addresses the recommendations of the BWRVIP-25 report,"BWR Core Plate Inspection and Flaw Evaluation Guidelines," pertaining to the TLAA for the RV core plate hold-down bolts. The relevant degradation mechanisms for this TLAA include loss of preload and cracking of the core plate rim hold-down bolts. Section 4.7.3.2 of the JAFNPP LRA indicated that the BWRVIP-25 report calculated the loss of preload for these bolts for the original 40-year licensed operating period. Appendix B to BWRVIP-25 projected this calculation to 60 years, demonstrating that the JAFNPP core plate rim hold-down bolts would experience, at most, a 19 percent loss of preload for the extended period of operation.

The staff determined that additional information is required concerning the data and analyses that were used to determine that the loss of preload at the end of the period of extended operation would be less than 20 percent. Therefore, the staff requests that the applicant provide additional information demonstrating that the requirements specified in the BWRVIP-25 report, including Appendix B, are applicable to JAFNPP, based on the following:

a. configuration and geometry of the JAFNPP core plate rim hold-down bolts;b. the temperature of the core plate rim hold-down bolts during normal operation, taking into consideration power uprate conditions; and c. projected bolt neutron fluence at the end of the period of extended operation, taking into consideration power uprate conditions.

Please include the actual values for bolt temperature and projected bolt neutron fluence in the above discussion, and explain how it was determined that the effects of temperature and neutron fluence at the end of the period of extended operation would result in less than a 20 percent loss of bolt preload. Provide a detailed description of the methodology and data used at JAFNPP to perform the above analyses, and include the basis for the stress relaxation curves.Finally the staff requests that the applicant demonstrate that, under the conditions stated in Scenario 3 of BWRVIP-25, Appendix A (determination of hold-down bolt loading with no credit for aligner pins or rim weld), the axial and bending stresses for the hold-down bolts with the mean and highest loading will not exceed the ASME Code,Section III allowable stresses for primary membrane and primary membrane plus bending, as a result of a 20 percent reduction in the specified bolt pre-load.

Clearly state the assumptions on which this analysis is based, taking into consideration the fact that the approach recommended in Appendix A of BWRVIP-25 is based on an elastic finite element analysis of the core plate and hold-down bolts.Attachment 1 Page 24 of 27 JAFP-07-0021 RAI 4.7.3.2-1 Response a. The core plate hold-down bolts at JAFNPP are the typical design for a BWR-4 identified in BWRVIP-15.

JAFNPP core plate bolts have no plant-specific characteristics.

b. and c.These sections of RAI 4.7.3.2-1 are requesting specific details related to a plant-specific analysis discussed in LRA Section A.2.2.7. (This is also addressed in audit question 483.) The details of the analysis are not available since it has not been performed at this time. In lieu of providing the details requested, JAFNPP will perform one of the following.
1. Install core plate wedges prior to the period of extended operation, or 2. Complete a plant-specific analysis to determine acceptance criteria for continued inspection of core plate rim hold down bolting in accordance with BWRVIP-25 and submit the inspection plan to the NRC two years prior to the period of extended operation for NRC review and approval, or 3. Perform inspection of core plate rim hold down bolts in accordance with ASME Code Section XI or in accordance with an NRC-approved version of BWRVIP-25.

If Option 2 is selected, the analysis to determine acceptance criteria will address the information requested in RAIs 3.1.2-2A and 4.7.3.2-1.

License renewal commitment 23 tracks this commitment.

RAI 4.7.3.2-2 Please indicate whether any cracking has been detected in the core plate rim hold-down bolts. If any cracking has been detected, clarify why there is no TLAA that addresses the evaluation of flaws due to cracking in the core plate rim hold-down bolts.RAI 4.7.3.2-2 Response JAFNPP has not detected any cracking of the core plate rim hold-down bolts.RAI 4.7-1 Radiation embrittlement may affect the ability of RV intemals, particularly the core shroud, to withstand a low-pressure coolant injection thermal shock transient.

The analysis of core shroud strain due to reflood thermal shock is based on the calculated lifetime neutron fluence. This analysis satisfies the criteria of 10 CFR 54.3(a). As such, this analysis is a TLAA. Explain why the analysis for core shroud strain due to reflood thermal shock is not addressed in the LRA.Note: For reference, please see the NRC staff's evaluation in section 4.2.2.4 of NUREG-1 796"Safety Evaluation Report Related to the License Renewal of the Dresden Nuclear Power Station, Units 2 and 3 and Quad Cities NuclearPower Station, Units 1 and 2," dated October 2004, which is available on the NRC website.Attachment 1 Page 25 of 27 JAFP-07-0021 RAI 4.7-1 Response The reflood thermal shock analyses discussed in NUREG-1796 are part of the current licensing basis for the Dresden Nuclear Plant, but are not part of the CLB for JAFNPP. There is no mention of reflood thermal shock in the JAFNPP UFSAR. Consequently, JAFNPP has no TLAA for reflood thermal shock and it is thus not included in the LRA.There is no regulatory requirement for this analysis.

It is our understanding that during early BWR licensing, the ACRS had a concern about reflood thermal shock and asked that early license applicants review it even though there was no specific requirement to do so. General Electric performed "generic" analyses that resolved the ACRS concerns.

The question and answer are documented in the UFSARs of those plants (such as Dresden) that were asked and responded to the ACRS question.

These responses may be considered part of their licensing basis. By the time JAFNPP applied for a license, the ACRS was satisfied and did not ask this question.

As a result, the Dresden analysis is not part of the JAFNPP CLB.RAI 4.7-2 Radiation embrittlement may affect the ability of the RV to withstand a low-pressure coolant injection thermal shock transient.

Explain why the analysis for reflood thermal shock of the RV is not addressed in the LRA. Note: For reference, please see the NRC staff's evaluation in section 4.2.2.3 of NUREG-1796 "Safety Evaluation Report Related to the License Renewal of the Dresden Nuclear Power Station, Units 2 and 3 and Quad Cities NuclearPower Station, Units 1 and 2," dated October 2004, which is available on the NRC website.RAI 4.7-2 Response The response to this question is the same as the response to RAI 4.7-1.RAI B.1.24-1 The applicant, in UFSAR supplement A.2.1.26, 'Reactor Vessel Surveillance Program," and in AMP B. 1.24, "Reactor Vessel Surveillance," states that it will implement the BWRVIP Integrated Surveillance Program (ISP) as specified in the BWRVIP-1 16 report, "BWR Vessel Internals Project Integrated Surveillance Program Implementation for License Renewal," at the JAFNPP.By letter dated March 1, 2006, the staff has issued the final SE for the BWRVIP-1 16 report and, therefore, the staff requests that the applicant include the following statement (shown bold underlined font) in the UFSAR supplement Section A.2.1.26 and in AMVP B.1.24 of the LRA."The ISP-BWRVIP-1 16 report which was approved by the staff W11 be implemented at JAFNPP with the conditions documented in Sections 3 and 4 of the staff's final SE of the BVWRVIP-116 report." Attachment 1 Page 26 of 27 JAFP-07-0021 RAI B.1.24-1 ResDonse LRA Sections A.2.1.26, "Reactor Vessel Surveillance Program," and B. 1.24, "Reactor Vessel Surveillance," are revised to add the following."The BWRVIP-1 16 report which was approved by the staff will be implemented at JAFNPP with the conditions documented in Sections 3 and 4 of the staff's final SE dated March 1, 2006, for the BWRVIP-116 report." RAI B.1.24-2 10 CFR Part 50, Appendix H, requires that an ISP used as a basis for a licensee implemented RV surveillance program be reviewed and approved by the NRC staff. The ISP to be used by the applicant is a program that was developed by the BWRVIP. The applicant will apply the BWRVIP ISP as the method bywhich the JAFNPP unit will comply with the requirements of 10 CFR Part 50, Appendix H. The BWRVIP ISP identifies capsules that must be tested to monitor neutron radiation embrittlement for all licensees participating in the ISP and identifes capsules that need not be tested (standby capsules).

Table 3-3 of the BWRVIP-1 16 report indicates that the capsules from JAFNPP unit are not tested. These untested capsules were originally part of the applicant's plant-specific surveillance program and have received significant amounts of neutron radiation.

The staff requests that the applicant include the following statement (shown bold underlined font) in the UFSAR supplement Section A.2.1.26 ofthe LRA."If the JAFNPP standby capsule is removed from the RPV without the intent to test it, the capsule will be stored in manner which maintains it in a condition Mhich would permit its future use, including during the period of extended operation, if necessary." RAI B.1.24-2 Response LRA Section A.2.1.26, "Reactor Vessel Surveillance Program," is revised to add the following."If the JAFNPP standby capsule is removed from the reactor vessel without the intent to test it, the capsule will be stored in a manner which would permit its future use." RAI B.1.24-3 The staff requests that the applicant provide information on whether it is currently implementing BWRVIP ISP at JAFNPP. If so, the applicant should reference the staff-approved license amendment request for implementing ISP at JAFNPP.RAI B.1.24-3 Response JAFNPP has implemented the BWR vessel and internals project (BWRVIP) Integrated Surveillance Program (ISP) as discussed in the NRC staffs final SE dated July 26, 2006 for TS Amendment

  1. 285. (TAC No. MC9682)Attachment 1 Page 27 of 27 JAFP-07-0021
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