ML061100129

2006/04/18-Oyster Creek - Response to NRC Request for Additional Information, Dated March 20, 2006, Related to Oyster Creek License Renewal Application

ML061100129
Person / Time
Site:	Oyster Creek
Issue date:	04/18/2006
From:	Gallagher M AmerGen Energy Co
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
%dam200606, 2130-06-20292, TAC MC7624
Download: ML061100129 (19)

Text

AmerGen SM Michael P. GallagheT, PE Vice President License Renewal Projects Telephone 610.765.5958 www.exeloncorp.com michaelp.gahlagher@exeloncorp.com An Exelon Company 10 CFR 50 10 CFR 51 10 CFR 54 AmerGen 200 Exelon Way KSA/2-E Kennett Square, PA 19348 2130-06-20292 April 1 El, 2006 U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555 Oyster Creek Generating Station Facility Operating License No. DPR-1 6 NRC Docket No. 50-219 Subjec::

Reference:

Response to NRC Request for Additional Information, dated March 20, 2006, Related to Oyster Creek Generating Station License Renewal Application (TAC No. MC7624)"Request for Additional Information for the Review of the Oyster Creek Nuclear Generating Station, License Renewal Application (TAC No. MC7624)," dated March 20, 2006 In the referenced letter, the NRC requested additional information related to Sections 2.4 and 3.5 of the Oyster Creek Generating Station License Renewal Application (LRA). Enclosed are the responses to this request for additional information.

If you have any questions, please contact Fred Polaski, Manager License Renewal, at 610-765-5935.

I declare under penalty of perjury that the foregoing is true and correct.Respec:tfully, Executed on 9*-/-? d; d 6 Michael P. Gallagher Vice President, License Renewal AmerGen Energy Company, LLC

Enclosure:

Response to 03/20/06 Request for Additional Information

40. I Iq April 18, 2006 Page 2 of 2 cc: Regional Administrator, USNRC Region I, w/o Enclosure USNRC Project Manager, NRR -License Renewal, Safety, w/Enclosure USNRC Project Manager, NRR -License Renewal, Environmental, w/o Enclosure USNRC Project Manager, NRR -OCGS, w/o Enclosure USNRC Senior Resident Inspector, OCGS, w/o Enclosure Bureau of Nuclear Engineering, NJDEP, w/Enclosure File No. 05040 Enclosure Response to 3/20/06 Request for Additional Information Oyster Creek Generating Station License Renewal Application (TAC No. MC7624)RAI 2.4.1-1 RAI 2.4.1-2 RAI 2.4.2-1 RAI 2.4.8-1 RAI 2.4.9-1 RAI 3.5-1 RAI 3.5-2 RAI 3.5-3 RAI 3.5-4 RAI 3.5-5 RAI 3.5-6 RAI 3.5-7 RAI 3.5-8 RAI 3.5-9 RAI 3.5-1 0 1 of 17 RAI 2.4.1-1 A review of LRA Table 2.4.1 indicate that drywell seismic support and anchorages are rnot within the scope of license renewal, though they are relied upon for drywell stability.

A component type "Biological Shield Wall -Lateral Support" is in the Table. The staff requests the applicant to provide justification for not including the drywell seismic lateral supports within the scope of license renewal.Response The drawell seismic lateral supports are in the scope of license renewal and subject to aging management review. The lateral supports are not specifically identified by name; but they are included in ASME Class MC component supports and evaluated with the Component Suppolts Commodity Group in license renewal application Section 2.4.18. Their aging management review is presented in Table 3.5.2.1.18, page 3.5-195.RAI 2.4.1-2 LRA Tables 2.4.1 and 2.4.2 do not incorporate refueling cavity seal components within the scope of license renewal, though the plant has experienced significant corrosion (as described in Item 4 of LRA Section 3.5.2.2) of the drywell as a result of leakage from the seal. The staff requests the applicant to include the seal in the scope of license renewal, or provide justification for not including it in the scope of license renewal.Resnooise The refueling cavity seals are referred to as refueling bellows in the application and described in Section 2.4.2, page 2.4-8. As discussed in this section, the refueling bellows are classified non-safety related and perform their design function only when the plant is shutdown for refueling.

The refueling bellows are not credited in the current licensing basis (CLB) for design basis events or accidents and their failure would not impact a safety function.

As a result scoping determined that the refueling bellows do not perform an intended function delineated in 10 Cl-R 54.4 (a), thus not included in Table 2.4.2.The cavity seals are also addressed in RAI 4.7.2-3. In response to RAI 4.7.2-3 (submitted April 7, 2006) we provided the following information:

The refueling seals at Oyster Creek consist of stainless steel bellows. In mid to late 1980's G;PU conducted extensive visual and NDE inspections to determine the source of water intrusion into the seismic gap between the drywell concrete shield wall and the drywell shell, and its accumulation in the sand bed region. The inspections concluded that the refueling bellows (seals) were not the source of water leakage. The bellows were repeatedly tested using helium (external) and air (internal) without any indication of leakage. Furthermore, any minor leakage from the refueling bellows would be collected in a concrete trough below the bellows. The 2 of 17 concrete trough is equipped with a drain line that would direct any leakage to the reactor building equipment drain tank and prevent it from entering the seismic gap (see Figures 1 and 2). The drain line has been checked before refueling outages to confirm it is not blocked.The only other seal is the gasket for the reactor cavity steel trough drain line. This gasket was replaced after the tests showed that it was leaking (see Figure 2). However the gasket leak was ruled out as the primary source of water observed in the sand bed drains because there is no clear leakage path to the seismic gap. Minor gasket leak would be collected in the concrete trough below the gasket and would be removed by the drain line similar to leaks from the refueling bellows.Additional visual and NDE (dye penetrant) inspections on the reactor cavity stainless steel liner identified significant number of cracks, some of which were through wall cracks. Engineering analysis concluded that the cracks were most probably caused by mechanical impact or thermal fatigue and not intergranular stress corrosion cracking (IGSCC). These cracks were determined to be the source of refueling water that passes through the seismic gap. To prevent leakage through the cracks, GPU installed an adhesive type stainless steel tape to bridge any observed large cracks, and subsequently applied the strippable coating. This repair successfully greatly reduced leakage and is implemented every refueling outage while the reactor cavity is flooded.Oyster Creek is currently committed to monitor the sand bed region drains for water leakage. A review of plant documentation did not provide objective evidence that the commitment has been implemented since 1998. Issue Report #348545 was issued in accordance with Oyster Creek corrective action process to document the lapse in implementing the commitment and to reinforce strict compliance with commitment implementation in the future, including during the period of extended operation.

In addition to the commitment to monitor the sand bed region drains and the reactor cavity concrete trough drains for water leakage (see Figures 1 and 2), Oyster Creek is committed to performing augmented inspections of the drywell in accordance with ASME Section Xl, Subsection IWE during the period of extended operation.

These inspections consist of periodic UT examinations of the upper region of the drywell and visual examination of the protective coating on the exterior of the drywell shell in the sand bed region. The visual inspection of the coating will be supplemented by UT measurements from inside the drywell once prior to entering the period of operation, and every 10 years thereafter during the period of extended operation.

3 of 17

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• Wg .l*FeZ -Drvwll to Reactor Cavit' Seal Detail 5 of 17 RAI 2.4.2-1 LRA Page 2.4.8 states that structural seals are within the boundary of evaluation, but without explaining what they are. The staff requests the applicant to identify all the structural seals in the reactor building.Response Component type structural seals or "seals" are used to designate seals other than those specifically used to fill penetrations.

For the reactor building, these seals consist of elastomers used as sealant for the superstructure metal siding, flood door seals, HELB door seals, secondary containment door seals, and seals in expansion joints of exterior concrete walls o1 the building.

The seals perform a leakage boundary intended function as designated in LRA Table 3.5.2.1.2, page 3.5-88.RAI 2.4.8-1 LRA Section 2.4.8, Fire Pond dam, states that the dam is classified as Safety Class 111.The staff requests the applicant to identify the location in the LRA or updated final safety analyslis report (UFSAR) where the definition of Safety Class Ill was provided.

If the definition was not provided in the LRA or UFSAR, the staff requests the applicant to provide a definition for Safety Class Ill.Resporise The Fire Pond Dam "Safety Class 111" classification is related to the hazard potential associated with property damage and/or loss of life should the dam fail. It is not associated with nuclear safety and is not defined in the UFSAR. The term was not defined in the application because it does not effect scoping, screening, and aging management of the dam. The Fire Pond Dam is in the scope of license renewal because it meets 1 OCFR 54.4 (a)(3) because it is relied upon in the safety analyses and plant evaluations to perform a function that demonstrates compliance with the Commission's regulations for fire protection (10 CFR 50.48).As described in LRA section 2.4.8, the dam is classified "Safety Class Ill" and subject to State of New Jersey Department of Environment Protection and Energy dam safety regulations.

The"Safety Class Ill" classification is assigned by the State of New Jersey to dams whose failure is not expected to result in a loss of life and/or significant property damage. This classification is synonymous to "Low-Hazard Potential" assigned to dams by FEMA in accordance with Federal Guidelines for Dam Safety.6 of 17 RAI 2.4.9-1 LRA Section 2.4.9, Fire Pumphouses, states that the pumphouse and the tank foundations are classified non-safety related, Seismic Class II. The staff request the applicant to identify the location in the LRA or UFSAR where the definition of "non-safety related, Seismic Class II" is provided.

If the definition was not provided in the LRA or UFSAFI, the staff requests the applicant to provide a definition for "non-safety related, Seismic Class II".Resporise Seismic classification of structures is defined in the UFSAR Section 3.8.3.2, Applicable Codes, Standards and Specifications, and Section 3.8.4.1, Description of the Structures.

According to these sections, there are two classes of structures for which earthquake design requirements apply as follows:* Class I -Structures and equipment whose failure could cause significant release of radioactivity or which are vital to a proper shutdown of the plant and the removal of decay heat.* Class II -Structures and equipment which are both essential and nonessential to the operation of the station, but which are not essential to a proper shutdown.The Fire Pumphouses and tank foundations are classified Seismic Class II structures based on UFSAFI definition above.For license renewal, the Fire Pumphouses and the tank foundations meet 10 CFR 54.4(a)(3) because they are relied upon in the safety analyses and plant evaluations to perform a function that de-nonstrates compliance with the Commission's regulations for fire protection (10 CFR 50.48). The pumphouses and the tank foundations do not meet 10 CFR 54.4(a)(1) because they are not safety related structures that are relied on to remain functional during and following design basis events. The pumphouses and the tank foundations do not meet 10 CFR 54.4(a)(2) because failure of non-safety related portions of the structures would not prevent satisfactory accomplishment of function(s) identified for 10 CFR 54.4(a)(1).

The structures are not relied upon in any safety analyses or plant evaluations to perform a function that demonstrates compliance with the Commission's regulation for Environmental Qualification (10 CFR 50.49), ATWS (10 CFR 50.62), or Station Blackout (10 CFR 50.63).RAI 3.6-1 LRA Table 3.5.2.1.1 indicates that fretting and lockup of suppression pool downcomers will be managed by ASME Section Xl, Subsection IWE, (AMP B.1.27). Directly, the downcomers are not part of the pressure boundary.

Subsection IWE does not provide examination requirements and acceptance criteria for downcomers.

However, as a convenience, the examinations of downcomers can be included in Subsection IWE requirements, with special provisions for examining the downcomers for 7 of 17 fretting or lockups in the plant-specific procedures.

The staff requests the applicant to provide (1) a discussion of operating experience related to downcomers fretting or lockups, and (2) the ISI provisions incorporated in the plant-specific IWE program.Response 1. Oyster Creek operating experience has not identified fretting or lockups of the downcomers.

Visual inspections conducted in accordance with ASME Section Xl, Subsection IWE has been limited to downcomer surfaces above water level in the torus.Areas potentially susceptible to fretting or lockup are submerged in torus water and scheduled for inspection at the end of the current 1 0-Year Interval in accordance with Table IWE-2500-1.

Consequently Oyster Creek has no operating experience with fretting or lockups of the downcomers.

2. The Oyster Creek ASME Section Xl, Subsection IWE includes examination of downcomers with the Vent System, Examination Category E-A, Item No. E1.20 in accordance with Table IWE-2500-1.

Examination method is visual, VT-3 in accordance with IWE. Parameters monitored are loss of material due corrosion and fretting or lockup at clamps that connect adjacent downcomers.

The inspection frequency is every 10 years, with 100% inspection at the end of the interval in accordance with Table IWE-2500-1.RAI 3.5-2 LRA Table 3.5.2.1.1 credits 10 CFR 50, Appendix J (AMP B.1.29) for management of downcomers "Loss of Material." It is not apparent, how the leak testing requirement of Appendix J will detect loss of material of downcomers.

The staff requests the applicant to discuss the use of Appendix J in managing loss of material in downcomers.

Respoise The Oyster Creek Primary Containment Leakage Rate Testing Program (LRT) is performed in accordance with 10 CFR 50 Appendix J Option B, Regulatory Guide 1.163, NEI 94-01.ANSI/ANS 56.8, and approved plant program documents and procedures.

10 CFR 50 Appendix J paragraph ilA, Type A test pretest requirements, requires that a general inspection of the accessible interior and exterior surfaces of the containment structure and component shall ba performed prior to any Type A test to uncover any evidence of structural integrity deterioration which may affect the containment structural integrity or leak-tightness.

The general inspection will detect loss of material due to corrosion on accessible surfaces of the containment including downcomers.

However, ASME Section Xl, Subsection IWE is the primary aging management program that is credited for managing loss of material of the downcomers.

8 of 17 RAI 3.5-3 Under component types "Reactor Pedestal" and "R.C Floor Slab," a reference is made to Table 1 item 3.5.1-29.

The discussion in 3.5.1-29 indicates that the concrete temperatures in the upper part of the drywell could be as high as 259 0 F. As a result, the reactor building drywell shield concrete had significant cracking.

However, the cause of the high temperature is not indicated.

In light of the above discussion, the staff requests the applicant to provide the following information:

a. Type and adequacy of the cooling system used to control the temperatures in drywell.b. Operating experience related to the reliability of the cooling system.c. Actions taken to reduce the high temperatures in the upper part of the drywell.d. A summary of the results of the last inspection of reactor pedestal, R.C. floor slabs, drywell lateral supports, and sacrificial shield wall, including the date of the inspection, and frequencies of inspection during the period of extended operation.

Response Table 1 Line Item Number 3.5.1-29 discussion paragraph states the temperature limits of 1 50 0 F and 200 0 F are exceeded only in the upper elevation of the drywell. The reactor pedestal and the reinforced concrete floor slab are not subject to elevated temperature inside the drywell. These structures are located below elevation 55' where the maximum drywell temperature during plant operation is 139 degrees. For this reason Table 3.5.2.1.1, page 3.5-60 indicates that a "None" for aging effect associated with NUREG-1 801 Table 2 line item III.A4-1 (T-10) which rolls up to Table 1 line item 3.5.1-29.

A plant specific note 7 was added to the LRA Table 3.5.2.1.1 for these components to provide a technical basis for the aging of "none". The plant specific nole states 'Reduction of strength and modulus due to elevated temperature is not aging effect requiring management.

See further evaluation in Section 3.5.2.2.1.3".

The further evaluation paragraph on page 3.5-17 states "... Concrete for the reactor pedestal, and the drywell floor slab (fill slab) are located below elev. 55' and are not exposed to the elevated temperature." As discussed in the LRA paragraph 3.5.2.2.1 item (3), the temperature inside the drywell during plant operation varies from 139 0 F at elevation 55' to more than 256 0 F in the upper elevations of the dryiNell, above elevation 95'.Thus, the temperature in the upper elevations of the drywell exceeds local and general limits for concrete in accordance with ACI 349. The affected concrete structure is the drywell shield walls above elevation 95'. The effect of elevated temperature on the drywell shield wall is discussed in detail in LRA Section 3.5, further evaluation paragraph 3.5.22.2 item (8). The following additional information is provided as requested by the Staff: a. The Drywell Cooling System consists of the drywell recirculating fan cooler units and -the Drywell Temperature Detection System. The Drywell Cooling System is a ventilation system designed to maintain temperature, humidity, and mixing in the drywell to control drywell pressure and protect the drywell and equipment inside from excessive heat. The Drywell Cooling System accomplishes this by circulating the drywell atmosphere (inerted nitrogen environment) through the drywell fan cooler units cooling coils and transferring heat from the drywell fan cooler units cooling coils to the Reactor Building Closed 9 of 17 Cooling Water (RBCCW) System.The Drywell Cooling System is comprised of five (5) recirculation fan cooler units including supply fans, demisters, supply and return ductwork, dampers, registers, instrumentation and controls.

In normal operation, four fans @ 20,000 cfm each are sufficient for cooling. From the fans, cooled nitrogen is fed to a supply/distribution ring header at El. 54' and delivered to the air space within the drywell.* 52,800 cfm is distributed through 5 supply air ducts to Zone I toward the lower part of the drywell for cooling of the recirculation pump motors.* 16,800 cfm is distributed through 9 supply registers to the remaining portions of Zone I.* 8,800 cfm is distributed through 5 supply air ducts to Zone II for cooling of the RPV surface and biological shield.* 1,600 cfm is distributed through a single supply air duct to Zone IlIl for cooling Df the RPV bottom cavity.The supply/distribution ring header at El. 54' does not directly provide cooling to the space above the reactor vessel head. 1,600 cfm is transferred through 8 ventilation hatches from Zone II to the space above the reactor vessel head.Return nitrogen is collected by a return duct ring header at El. 91'-7".* 54,400 cfm is returned to the return duct ring header through 5 return ducts in the lower part of the drywell.* 24,000 cfm is returned to the return duct ring header through 5 return ducts located directly on the return duct ring header.* 1,600 cfm is returned from the space above the reactor vessel head to the return duct ring header through 3 return ducts.The return duct ring header at El. 91-7" does not directly collect flow from the Zone IlIl RPV bottom cavity area. Nitrogen in this area exits Zone IlIl through access openings and is collected by the return ducts in the lower part of the drywell (Zone I).The Drywell Temperature Detection System provides information to the operators in the Control Room for the monitoring and recording of the drywell atmosphere temperature at various locations, and for the determination of the drywell bulk temperature during normal operation of the plant. The Drywell Temperature Detection System is comprised of local drywell temperature instrumentation and includes duct mounted temperature elements located in the supply and return portions of the recirculation fan ducts. The drywell temperatures are monitored by the Plant Computer System and are recorded on Control Room recorders and local panel recorders in the Reactor Building.The Oyster Creek drywell cooling system is designed to maintain the drywell bulk temperature below 150 0 F as discussed in item (c) below. The system adequately performs this function.b. The cooling system is maintained to maximize reliability.

Drywell fan motors, on 4 fans, were replaced in the mid 90's with direct drive motors. This change eliminated the possibility for belt breakage or slipping.

The fifth fan, which has the original belt driven 10 of 17 motor, is maintained as a spare, and is used during periods of peak drywell temperature.

During refueling outages, PM's are performed on all fans/motors.

Cooling coils are cleaned, bearings are greased, and vibration data is obtained on all bearings.

Belts are replaced on the one belt driven fan. There have been no significant component failures in recent years that have rendered one train inoperable.

c. There have been no actions to reduce temperature in the upper elevations.

The drywell cooling system has functioned within design bases to adequately cool the drywell.Drywell bulk temperature is maintained under the 150-degree limit, even during the highest heat periods. The drywell Bulk temperature is a calculated value using a weighted average of all the thermocouples.

It is the single value that is used for action levels such as EOP entry, plant shutdown, etc.d. Structures inside the drywell were last inspected in October 16, 2002 in accordance with the Oyster Creek Structures Monitoring aging management program (B.1.31).

The reactor pedestal, drywell R.C floor slab, and liner plate for the sacrificial shield wall were found structurally sound and able to perform their intended function.Inspection of the drywell lateral supports is included in the ASME Section Xl, Subsection IWE as Non-Mandatory Augmented Inspections during the current term. The last inspection was conducted during the refueling outage in 2004. The inspection report did not identify degradations that would impact the intended function of the supports.The reactor pedestal and the R.C. floor slab will be monitored on a frequency of every refueling outage during the period of extended operation in accordance with the Structures Monitoring aging management program (B.1.31).

The sacrificial (biological) shield wall carbon steel liner has previously experienced cracking.

The cracking was evaluated and determined not to impact the intended function of the wall. This Carbon steel liner is monitored under CLB every refueling outage, consistent with an existing NRC commitment, and will continue to be monitored every refueling outage during period of extended operation as part of the Structures Monitoring Program (B.1.31).The drywell lateral supports are included in Class MC component supports and will be monitored under ASME Section Xl, Subsection IWF (B.1.28) during the period of extended operation.

Inspection frequency is every 10 years in accordance with ASMI-Section Xl, Subsection IWF as approved by 10 CFR 50.55 (a).RAI 3.E;-4 Component type "Shielding Blocks and Plates," uses patented material "Permali," for which no aging effects are indicated in Table 3.5.2.1.1.

The staff requests the applicant to provide a brief description of the material, and the AMR results that justified that it does not need aging management during the period of extended operation.

11 of 17 Response Permali consists of vacuum impregnated material based on wood veneers (rosewood) and phenolic resin. The material was provided in Oyster Creek original design in combination with steel blocks to provide neutron shielding around recirculation piping nozzles at biological shield wall penetrations.

The material is designed for its operating environment and aging management reviews did not identify aging effects requiring aging management during the period of extended operation.

RAI 3.5-5 For all component types described in Table 3.5.2.1.1 (Primary Containment), the "water chemistry program" is vital for the components fully or partially submerged in water, ill addition to the programs noted in the individual component types. The staff requests the applicant to provide reasons for not including water chemistry program to manage the aging degradation of these components.

Response Oyster Creek recognizes that water chemistry is vital for mitigating loss of material due to corrosion for carbon and stainless steel components, and cracking of stainless steel components exposed to treated water environment.

Oyster Creek torus water chemistry is monitored in accordance with industry guidelines (BWRVIP-1

30) as described in Water Chemistry (B.1.02) aging management program.The Water Chemistry (B.1.02) aging management program was not credited for managing the effects of aging of the torus and structural components subject to torus water because ASME.Section Xl, Subsection IWE (B.1.27), 10 CFR 50 Appendix J (B.1.29), and the Protective Coating Monitoring and Maintenance Program (B.1.33) are determined adequate to manage their aging effects. This is consistent with the January 2005 draft NUREG-1 801 which credits only ASME Section Xl, Subsection IWE, and 10 CFR 50 Appendix J Programs.

The September 2005 NUREG-1 801 Rev. 1 added treated water environment to steel elements of the containment (II.B1.1-2 (C-19)). However, this line item does not credit water chemistry aging management for any of the components subject to treated water.Based on the discussion above Oyster Creek concluded that, while torus water chemistry is vital and maintained in accordance with BWRVIP-130, the Water Chemistry Program (B.1.02) need not be credited to provide reasonable assurance that aging effects of structural components exposed to treated water are adequately managed. The credited ASME Section Xl, Subsection IWE (B.1.27), 10 CFR 50 Appendix J (B.1.29), and the Protective Coating Monitoring and Maintenance Program (B.1.33) are determined adequate to manage their aging effects. This is consistent with NRC Staff Guidance provided in NUREG-1 801.12 of 17 RAI 3.5-6 The through-wall cracking of Fitzpatrick torus indicates a need for closer examination of the highly restrained and structurally discontinuous areas subjected to operational cyclic loads. The prime aging management program used for managing degradation of the primary containment structure is Subsection IWE (AMP B.1.27). The program is focused towards detecting loss of material.

The staff requests the applicant to discuss how the program would detect initiation of such cracking in the Oyster Creek primary containment.

Respooise The Oyster Creek ASME Section Xl, Subsection IWE aging management program (B.1.27) is not credited for managing crack initiation and growth. The program is based on visual examinations that may not detect cracking experienced at Fitzpatrick.

However crack initiation and growth mechanism experienced at Fitzpatrick is not applicable to Oyster Creek as explained below.The initial review (2005) of the Fitzpatrick torus leak operating experience determined that the crack was related to design and operating conditions that are not applicable to Oyster Creek.Analysis performed by Fitzpatrick indicated that the most likely cause for the initiation and propagation of the crack was the hydrodynamic loads of the turbine exhaust pipe during HPCI operation coupled with highly restrained condition of the torus shell at the torus column support.The cracking occurred in the heat-affected zone of the lower gusset plate of the ring girder al the torus column support. Fitzpatrick concluded that the crack was initiated by cyclic loading due to condensation oscillation during HPCI operation.

The condensation oscillations induced on the torus shell may have been excessive due to lack of a HPCI pipe sparger. The combined operation of the HPCI system and safety relief valve (SRV) discharges during the northeast grid blackout disturbance of August 2003 may have initiated the crack. The HPCI system operated approximately 14.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> and SRVs lifted five times over a period of 28 hours3.240741e-4 days <br />0.00778 hours <br />4.62963e-5 weeks <br />1.0654e-5 months <br /> following the grid disturbance.

Oyster Creek does not have a HPCI system and was not subject to events described above.Since the initial review, NRC issued Information Notice 2006-01, Torus Cracking in BWR Ma-k I Containment, on January 12, 2006, to alert licensees of Fitzpatrick condition.

Exelon is currently reviewing the impact of the Fitzpatrick experience on Oyster Creek. Corrective actions will be initiated if it is determined the condition described in the information notice are applicable to Oyster Creek.RAI 3.5-7 LRA Table 3.5.3.1.18 indicates that the aging of Class MC component supports is managed by ASME Section Xl, Subsection IWF during the CLB. However, a review of the"Enhancement" in AMP B.1.28 (ASME Section Xl, subsection IWF) indicates that the program will be enhanced during the period of extended operation to include additional 13 of 17 MC supports and underwater structures in the torus. The staff requests the applicant to provide clarifications regarding the inspection of Class MC supports during the CLB and during the period of extended operation.

Resorise The reference to LRA Table 3.5.3.1.18 is a typographical error and should read Table 3.5.2.1.18.

LRA Table 3.5.2.1.18 is for aging management review of Class MC component supports during the period of extended operation not during CLB. The table reflects enhancements described in ASME Section Xi, Subsection IWF (B.1.28) aging management program.For the current term, inspection of some Class MC component supports is conducted under ASME Section Xl, Subsection IWF, and others are under ASME Section Xl, Subsection IWE."Non-Mandatory Augmented Inspections".

Those included under Non-Mandatory IWE Augmented Inspections consists of vent header supports, downcomer bracing, and drywell stabilizers.

Other supports are in the scope of IWF. Supports submerged in torus water are treated as inaccessible under the current term and are not included in the inspection plan for either IVVF or IWE.For license renewal, all Class MC component supports are included in the scope of IWF.Subme ged supports inside the torus will be monitored under IWF and will be inspected by divers who conduct inspection of the submerged torus shell or when the torus is dewatered.

RAI 3.5-8 LRA Tables 3.5.2.1.6, 3.5.2.1.15, 3.5.2.1.16, and 3.5.2.1.17 identify loss of preload as the aging offect requiring management for structural bolts, and the structural monitoring prograirn (B.1.31) as its aging management program. The Structural Monitoring Program states that exposed surfaces of bolting are monitored for indications of loss of preload, and that the program relies on procurement controls and installation practices, defined in plant procedures, to ensure that only approved lubricants and proper torque are applied consistent with the GALL Report bolting integrity program. LRA B.1.12 Bolting Integrity Program states that the program takes exception to the GALL Report and that the aging management of structural bolting is addressed by the Structural Monitoring Program (B.1.31).

The staff requests the applicant to address the following:

a. The applicant needs to resolve the apparent inconsistencies that the Structural Monitoring Program states that the proper torque for bolts is applied consistent with the GALL Report bolting integrity program while the Bolting Integrity Program takes exception to GALL Report and refers the aging management of structural bolting back to the structural monitoring program.b. Does the identification of the loss of preload of structural bolts by visual 14 of 17 inspection or by applying a torque wrench? If it is by visual inspection, explain how the loss of preload can be estimated by visual inspection.

c. LRA Section B.1.31 states that the Structural Monitoring Program relies on procurement controls and installation practices, defined in plant procedures, to ensure that only approved lubricants and proper torque are applied. The staff believes that bolt procurement controls and installation practices were supposedly used before, during, or immediately after the bolts were installed.

Since the Structural Monitoring Program is being used to inspect structural bolts after the bolts were installed for sometime, the staff requests the applicant to explain how could the Structural Monitoring Program rely on bolt procurement controls and installation practices.

d. Are there any structural bolts or fasteners, which have a yield strength equal to or greater than 150 ksi, managed by the structural monitoring program? If yes, provide justification for not using the bolting integrity program as the aging management program for structural bolts.Responise a. The exception to NUREG-1 801 referred to in the Bolting Integrity Program is that the NSSS component support and structural bolting is expected by NUREG-1 801 to be covered by the Bolting Integrity Program. These are instead covered by the Structures Monitoring Program, B.1.31 for structural bolting, ASME Section Xl, Subsection IWE (B1.27) for Primary Containment pressure bolting and ASME Section XI, Subsection IWF aging management program, B.1.28 for ASME Section Xl Class 1, 2, and 3 and Class MC support members. The same procurement and installation procedures credited in the Bolting Integrity program (B.1.12) are also applicable to the structural bolting.b. Structural bolting applications at Oyster Creek do not require specific predetermined bolting preload to assure the associated structural intended functions are maintained.

Structural bolting is assembled using approved bolting materials and lubricants.

Bolted connections are assembled using vendor recommended methods, turn-of-the-nut methods, or standard torque values for the applicable bolt size and material.

For structural bolting, loss of preload will not impact the bolted connection intended function unless the bolts become loose such that the integrity and geometry of the bolted connection is affected.

This aging effect is managed by visual inspection for loose or missing nuts and bolts.c. The same procurement and installation procedures credited in the Bolting Integrity program (B.1.12) are also applicable to the structural bolting. The Structures Monitoring Program is credited because the Structures Monitoring Program provides for visual inspections of the structural bolted connections.

d. Structural bolts that have yield strength equal to or greater than 150 ksi are used in limited structural applications at Oyster Creek, but those bolts are not subject to 15 of 17 significant preload stress, therefore cracking would not be expected.

The Structures Monitoring Program (B.1.31) includes structural bolting inspections for loss of material due to corrosion, and visual inspections for loose nuts, missing bolts, or other indications of loss of preload.RAI 3.5-9 LRA Table 3.5.2.1.7 lists Structural Monitoring Program as the AMP for penetration seals of elasitomer and grout in the soil environment.

The AMP in LRA, Appendix B states that the program will require inspection of penetration seals, but does not state how the inspection should be conducted for penetration seals of elastomer and grout in the soil environment and the frequency of the inspection.

The staff requests the applicant to describe the inspection method and frequency for penetration seals of elastomer and grout in the soil environment.

Response Penetration seals of elastomer and grout listed in Table 3.5.2.1.7 are used to seal Exhaust Tunnel walls, which are subject to soil environment on the exterior and indoor air on the interior.The soil side is considered inaccessible and inspected as part of concrete inspection if exposed for any reason. The seals inside the tunnel are accessible and are visually inspected on a frequency of 4 years in accordance with the Oyster Creek Structures Monitoring aging management program (B.1.31).

Parameters monitored include cracking of grout and change in material properties of elastomer.

The seals are also observed for moisture and indication of water intrusion.

RAI 3.5-10 LRA Table 3.5.2.1.7 lists aluminum material embedded in concrete, and states no aging effect and requiring no AMP. The ACI Building Code prohibits the use of aluminum in structural concrete unless it is coated or covered to prevent aluminum-concrete reaction or electrolytic action between aluminum and steel. The staff requests the applicant to justify the use of aluminum material in concrete and to explain why there is no aging effect and that an AMP is not required.Resporise As required by ACI, the concrete is not in direct contact with aluminum.

Oyster Creek Specification for placement of concrete requires that where aluminum will contact concrete, the contact surface of the metal shall be coated with not less than one coat of zinc chromate primer and one heavy coat of aluminum pigmented asphalt paint.16 of 17

References:

1. Letter J.C. DeVine, Jr. (GPU) to U. S. Nuclear Regulatory Commission, Oyster Creek Drywell Containment, dated December 5, 1990.17 of 17