ML061150320

2006/04/17-Oyster Creek - Responses to Action Items Associated with Plant License Renewal Audits

ML061150320
Person / Time
Site:	Oyster Creek
Issue date:	04/17/2006
From:	Gallagher M AmerGen Energy Co
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
%dam200606, 2130-06-20316, TAC MC7624
Download: ML061150320 (41)

Text

AmerGen SM Michael P. Gallagher, PE Telephone 610.765.5958 An Exelon (Company Vice President www.exeloncorp.com License Renewal Projects michaelp.gallagher@exeloncorp.com 10 CFF1 50 10 CFR 51 ArnerGen 10 CFR 54 200 Exelon Way KSA/2-E Kennett Square, PA 19348 2130-013-20316 April 17, 2006 U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555 Oyster Creek Generating Station Facility Operating License No. DPR-16 NRC Docket No. 50-219

Subject:

Responses to Action Items Associated with Oyster Creek Generating Station License Renewal Audits (TAC No. MC7624)

References:

1. December 9, 2005 Letter 2130-05-20238 from C. N. Swenson to USNRC -"Additional Commitments Associated with Application for Renewed Operating License -Oyster Creek Generating Station" 2. March 30, 2006 Letter 2130-06-20293 from Michael P. Gallagher to USNRC -"Reconciliation of Oyster Creek Generating Station License Renewal Application with September 2005 Revision 1 NUREG-1800 and NUREG-1 801" (TAC No.MC7624)3. April 4, 2006 Letter 2130-06-20284 from Michael P. Gallagher to USNRC -"Commitments Associated with Containment (Drywell and Torus) Condition Monitoring Related to AmerGen Application for Renewed Operating License -Oyster Creek Generating Station" (TAC No. MC7624)During the Aging Management Program (AMP) and Aging Management Review (AMR) Audits associated with Oyster Creek License Renewal, AmerGen Energy Company, LLC (AmerGen)responded to numerous questions from the NRC auditors.

These questions and the associated responses were captured in a Question and Answer (Q&A) database, which was periodically updated and provided to the Audit team.Responses to Audit questions involved things such as clarification of existing information contained in the License Renewal Application (LRA), provision of references, explanation of the technical basis for information in the License Renewal Application, and in some cases, commitments to take future actions that will have the effect of updating or modifying the LRA.The contents of the Q&A database were reviewed to identify responses wherein we committed to take such future actions. Enclosure 1 contains the subset of Q&A items that involve future actions that AmerGen committed to take as a result of the Audits. This letter confirms our commitment to implement these actions as described.

Implementation is being tracked within the AmerGen action tracking process, to be completed, as necessary, prior to the period of extended operation.

• 41,4 April 17, 2006 Page 2 of 2 AmerGen will also be providing a supplemental submittal updating the regulatory conimitmerits made in Table A.5 from Appendix A of the LRA to include commitments made during the course of NRC's review of the LRA.The letters referenced at the beginning of this letter provide additional documentation confirming commitments related to GALL reconciliation, Containment condition monitoring and fatigue analysis.

These references may also be useful to the Staff in closing out AMP and AMR Audit-related issues.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.Respectfully, Executed on 07 ,/7- 2Ai Michael P. Gallagher Vice President, License Renewal AmerGen Energy Company, LLC

Enclosure:

Audit Questions

& Answers Impacting the License Renewal Application 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 U.SNRC 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 Page 1 of 39 Enclosure Audit Questions and Answers Impacting the License Renewal Application Enclosure Page 2 of 39 teni Nlo AMP-037 Topic: One-Time Inspection Onestion: AMP B.1.24 One-Time Inspection (B.1.24-3)

The program description for OCGS AMP B.1.24 lists seven intended uses of this program. However, the OCGS LRA includes the following intended uses for this AMP that are not included in this list:- (1) Verify the effectiveness of the Selective Leaching of Materials p ogram, AMP B.1.25 (see Table 3.3.1, item 43); (2) Verify the effectiveness of the 10 CFR Part 50, Appendix J program, AMP B.1.29 (see Section 3.3.2.2.7, item 3); (3) Verify the effectiveness of the Generator S;tator Water Chemistry Activities program, AMP B.2.3 (see Section 3.3.2.2.7, item 3 and 3.3.2.2.10, item 2). Please clarify why the intended uses listed above are not listed in the program description for OCSG AMP 13.1.24.Also, please identify any other intended uses that are not listed.Response: (1) In LRA Table 3.3.2.1.29 "Reactor Building Closed Cooling Water System," the One-Time Inspection program was identified (with an "E" Industry Standard Note) in addition to the Closed-Cycle Cooling Water System aging management program and Selective Leaching of Materials aging management program for cast iron pipe exposed to a closed cooling water environment as specified for GALL Vol #2 VII.C2-7 (A-50).The One-Time Inspection aging management program does not verify the effectiveness of the Selective Leaching of Materials aging management program. As described in AMP B.1.25, The Selective Leaching of Materials aging management program is itself a one-time inspection to confirm that loss of material due to the selective leaching aging mechanism is not occurring.

The One-Time Inspection aging management program does verify the effectiveness of the Closed Cycle Cooling Water aging management program (in stagnant or low flow piping areas only) at managing the loss of material due to pitting and crevice corrosion.(Administrative update) LRA Table 3.3.1, item 43 will be corrected per LRCR #227. -MAM 4/13/2006 (2) The verification of the effectiveness of the 10 CFR Part 50, Appendix J aging management prog am, AMP B.1.29, is included in the Program Description of OCGS AMP B.1.24 as "To confirm loss of material in steel piping, piping components, and piping elements is insignificant in an indoor air (internal) environment." (3) The verification of the effectiveness of the Generator Stator Water Chemistry Activities aging management program, AMP B.2.3, is included in the Program Description of OCGS AMP B.1.24 as "To confirm the effectiveness of the Water Chemistry program to manage the loss of material and crack initiation and growth aging effects."

Enclosure Page 3 of 39 Itent No AMP-055 Topic: FEEDWATER NOZZLE Ouestion: B.1.5 BWR F:EEDWATER NOZZLE (B.1.5-6)

Please discuss whether OCGS is planning to implement monitoring in the thermal sleeve bypass, to detect leakage due to degraded thermal sleeve seals and welds, during the period of extended operation.

Resrponse:

While not required by NUREG-0619 the inspection of the feedwater and CRD nozzles includes a visual inspection of the sparger to nozzle interface to detect signs of bypass flow that would lead to degrada:ion of the thermal sleeve. Inspections specified for the 1 7R outage feedwater sparger were identified in SP-1302-56-130, Revl as VT-3 for exposed surfaces of feedwater sparger, welds, flow holes, and attachments in accordance with the NDE procedure NDE-VIS-04, "Visual Examination for Reactor Vessel internals." A V/T-3 exam of the entire feedwater sparger includes the center transition area in the nozzle. No sign of discoloring due to leakage flow was observed.The 2004 CRD nozzle inspection report provided objective evidence that the CRD nozzle blend radius area was inspected for signs of bypass flow around the thermal sleeve. The report indicates no evidence of bypass leakage was found. The feedwater nozzle was also inspected for indications of thermal sleeve bypass flow. Again no indications of bypass flow were found; however the feedwater nozzle inspection reports did not explicitly discuss results for the thermal sleeve. A review of previous feedwater nozzle inspection reports did not record explicitly the results of the inspection for signs of bypass flow leakage. To ensure future inspections clearly describe the results of inspection for thermal sleeve bypass flow, the Oyster Creek BWR Vessel Internals program (B.1.9) will be enhanced to include and document the condition of the CRD and Feedwater Nozzle thermal sleeves. The Rx Internals program was selected for this enhancement, because the thermal sleeves are not pressure boundary components and are best treated as internal components.

Table 3.1.2.1.5 will also be changed to reflect that the appropriate aging management program for thermal sleeves is the BWR Reactor Vessel Internals program, B.1.9.

Enclosure Page 4 of 39 Item No AMP-071 Topic: ASME Secdon XI, Subsection IWE ut'estion: (B.1.27-3):ln the OCGS AMP B.1.27 discussion of operating experience, the applicant discusses three (3)areas where containment degradation has been observed.

These are the upper region of the drywe'l shell;the sand bed region at the base of the drywell; and the suppression chamber (Torus) and vent systEm.Sand bed region at the bottom of the drywell -The applicant states that sand was removed and a protective coating was applied to the shell to mitigate further corrosion.

The coating is monitored periodically under LRA AMP B.1.3:3 Protective Coating Monitoring and Maintenance Program. The reader is directed to program B.1.33 for additional details. LRA B.1.33 identifies this coating to be within its scope; the discussion of operating experience in LRA B.1.33 is similar to the discussion of operating experience in LRA B.1.27.Please provide the following information pertaining to aging management of the sand bed region: (a) At the present time, is monitoring and maintenance of the coating in the sand bed region included in the scope of the current Protective Coating Monitoring and Maintenance Program or is it performed as part of the current IWE program?(b) Please provide the implementing procedure for this activity, preferably in both hard copy and electronic format.(c) Does LR aging management of the containment shell in the sand bed region include both the augmented IWE activities (as delineated in question B.1.27-2 above) and the coating monitoring and maintenance activities under B.1.33? If only B.1.33 is credited, please provide the technical basis for concluding that the augmented IWE activities are not necessary.

Resnonse: a) Monitoring and maintenance of the coating in the former sand bed region is included in the scope of the Protective Coating Monitoring and Maintenance Program (B.1.33)b) The sand bed region coating is in accordance with specification SP-1302-32-035 and SP-9000-06-003.

These documents are included with Program B.1.33.c) The Protective Coating Monitoring and Maintenance Program is credited for aging management of the sand bed region. It is not included in augmented inspection required by IWE. As stated in IWE program (B.1.27) operating experience, corrective actions that include cleaning and coating of the sand bed region implemented in 1992 have arrested corrosion.

The coated surfaces were inspected in 1994,1996, 2000, and 2004. The inspection showed no coating failure or signs or degradation.

Thus, the region is no,: subject to augmented inspection in accordance with IWE-1240.

The coating will be inspected every other refueling outage during the period of extended operation consistent with NRC commitments for the current term.Oyster Creek will also perform periodic UT inspections of the drywell shell thickness in the sand bed region as described in response to NRC Questions AMP-141 and AMP-209.Oyster Creek will also enhance the Protective Coating Monitoring and Maintenance Program (B.1.33) to require inspection of the coating credited for corrosion (Torus internal, vent system internal, sand bed region external) in accordance with ASME Section Xl, Subsection IWE. For details of the enhancements refer to response to NRC Question AMP-188 for details. Revised response to reference AMP-188, and AMP-209, which contain additional commitments and clarification discussed with NRC Staff on 1/26/2006.

Enclosure Page 5 of 39 Item No AMP-075 Topic: RG 1.127, Inspection of Water-Control Structures Ouestion: (B.1.32-3):

LRA Appendix B, Section B.0.5 identifies AMP B.1.32 as an existing program. The Program Description states that this AMP is part of the Structures Monitoring Program, and further states the program will be used to manage. The scope of the six enhancements listed for AMP B.1.32 encompass many of the elements that normally would be part of an existing inspection program for water-control structures.

Consequently, the applicant is requested to (a) specifically describe the scope of the currently existing program, including the structures and components in the scope of the existing program; the aging effects that are monitored; the inspection methods employed;and the inspection frequency; and (b) specifically describe the scope of AMP B.1.32, including the structures and components in the scope of AMP B.1.32; the aging effects that are monitored; the inspection methods employed; and the inspection frequency.

Response: a) RG 1.127, Inspection of Water-Control Structures is implemented through the Structures Monitoring Program, B.1.31. The scope of the program includes the Intake Structure and Canal, and the Dilution Structure.

Components monitored include earthen control structures (intake canal, embankment) and reinforced concrete structures.

The aging effects monitored include cracks, sinkholes, and embankment collapse of the intake canal embankment.

Concrete structures are monitored for cracks, spalling and scaling, rebar exposure, rust stain, structural settlement, and rebar corrosion.

The method of inspection is visual inspection.

Inspection frequency of accessible areas is every 4 years. Inaccessible areas of the structures are inspected whenever an opportunity occurs.b) The scope of the enhanced program includes structures and components that are in scope of the existing program. In addition, the scope is enhanced to include the Fire Pond Dam inspection, inspection of submerged components of the Intake Structure and Canal, the Dilution structure, the Fire Pond Dam, and the earthen dike between the Intake and the Discharge Canal. The aging effects monitored include cracks, sinkholes, and embankment collapse of the intake canal embankment.

Concrete structures are monitored for cracks, spalling and scaling, rebar exposure, rust stain, structural settlement, and rebar corrosion.

Enhancement to the aging effects include the addition of monitoring concrete structures for change in material properties due to leaching of calcium hydroxide, inspection of wooden components for loss of material and change in material properties, and loss of material due to corrosion for steel componerts.

The method of inspection is visual inspection.

Inspection frequency of accessible areas is every 4 years.Inaccessible areas are inspected whenever an opportunity occurs.The program will be enhanced to require performing a baseline inspection of submerged water control structures prior to entering the period of extended operation.

A second inspection will be performed 6 years after this baseline inspection and a third 8 years after the second. After each inspection an evaluation will be performed to determine if the identified degradations warrant more frequent inspections or corrective actions.This constitutes a new enhancement not previously identified in the LRA (also see AMP-077)

Enclosure Page 6 of 39 Itenm No AMP-077 Topic: RG 1.127, Inspection of Water-Control Structures Ouestion: (B.1.32-5):The Program Description for AMP B.1.32 states Inspection frequency is every four (4) years;except for submerged portions of the structures, which will be inspected when the structures are deivatered, or on a frequency not to exceed 10 years. GALL AMP XI.S7 identifies an inspection frequency of 5 years.Please explain why the 10 year inspection frequency is NOT identified as an exception to the GALL AMP.Please also provide the technical basis for concluding that a 10 year inspection frequency is sufficient for submerged portions of structures.

Response: The 5 year inspection frequency identified in GALL AMP XL.S7 is based on Regulatory Guide 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants. Oyster Creek is not committed to inspect underwater structures on a frequency of 5 years as explained below. The Oyster Creek RG 1.127, Inspection of Water Control Structures Associated with Nuclear Power Plants was reviewed by NRC and approved the program. For this reason the 10 year frequency was not identified as an exception to the GALL AMP.The Oyster Creek original design did not commit to the requirements of RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants. However in response to NUREG-0822, Integrated Plant Safety Assessment Systematic Evaluation Program (SEP) Topic ll-3.C, Oyster Creek evaluated water control structures consistent with the requirements of RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants, and presented to the NRC the evaluation results and the prcposed Oyster Creek RG. 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants surveillance program. In a letter dated June 24, 1982, the NRC provided the results of its review and comments on the proposed surveillance program This letter and NUREG-1382, Safety Evaluation Report related to the full-term operating license for Oyster Creek Nuclear Generating Station formed the basis for the existing Oyster Creek RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants aging management program.The existing Oyster Creek RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants aging management program did not commit to the inspection frequency of 5 years specified in Regulatory Guide 1.127 revision 1. Inspection of water control structures is included in the Oyster Creek Structures Monitoring Program (B.1.31);

except for the Fire Pond Dam, which is inspected under the New Jersey Dam Safety Standards, N.J.A.C 7:20-1.1 et seq.The Oyster Creek Structures Monitoring Program (B.1.31) requires inspection of accessible water control structures on a 4 year frequency consistent with the frequency for implementing the requirements o" the 10 CFR Part 50.65, Maintenance Rule. The program considers underwater structures inaccessible and requires inspection only when they become accessible.

For license renewal, we enhanced the program to require inspection of underwater structures before entering the period of extended operation, and on a frequency of 10 years during the period of extended operation.

After each inspection, the identified degradations will be evaluated to determine if more frequent inspections are warranted to ensure that the intended function of the Enclosure Page 7 of 39 water control structures is not adversely impacted.

The 10 year frequency is selected based on plant operating experience with the Intake Structure and Canal. This operating experience identified concrete degradations, however none were significant enough to impact the intended function of the structure.

The above information was presented to the NRC Staff during the AMP audit week. The Staff indicated that it has a concern that the Oyster Creek operating experience may not be sufficient to conclude with reasonable assurance the 10 year frequency is adequate to detect aging effects before an intended function is impacted.

As a result of the Staff's concern, Oyster Creek agreed to perform a baseline inspection of submerged water control structures prior to entering the period of extended operation.

A second inspection will be performed 6 years after the baseline inspection.

A third inspection will be performed 8 years after the second inspection.

Following each inspection, the identified degradations will be evaluated to determine if more frequent inspections are warranted or there is a need for corrective actions to ensure that age related degradations are adequately managed.

Enclosure Page 8 of 39 IRet eNo AMP-1 05 Topic: GALL AMP: Xl.M26 Fire Protection LRA AMP: B.1.19 Question: Adequacy of Implementing Procedures.

GALL AMP: XL.M26 Fire Protection, Program Element 3, Parameters Monitored/inspected, requires that Hollow metal fire doors be visually inspected to verify the integrity of door surfaces and for clearances.

The OC Basis for consistency with this AMP Element states: Fire doors will be visually inspected by designated qualified personnel for signs of degradation such as wear, missing paits, holes in the skin, clearances, and other degradation per Oyster Creek plant specific program 101.2, Oyster Creek Site Fire Protection Program. Procedures direct visual inspection of the fire door clearances..

Inspections performed under the referenced procedures (Procedure 101.2 or Fire Marshal Tours) do not appear to include a verification of door clearances.

Please provide implementing procedure which assures consistency with the GALL criterion for verifying clearances.

Response: The Oyster Creek Fire Protection Program will be enhanced to require that clearances of fire doors in the scope of license renewal be routinely inspected every two years. Procedure 101.2 Attachment 101.2-3 Section 5.A.1 requires that these fire doors be intact, and Section 5.B.2 requires these doors be verified functional.

The routine clearance inspection requirement will be added to this procedure.

Currently, fire doors identified as secondary containment receive routine clearance checks, and other fire doors in the scope of license renewal receive clearance checks if they have been damaged or undergone maintenance such that the clearances may have been physically altered. The enhancement of requiring routine clearance checks for all fire doors in the scope of license renewal will provide assurance that door clearances will be satisfactory.

E nclosure Page 9 of 39 Itenm No AMP-1 48 Topic: Abovegrould Outdoor Tanks Ouestion: In Element 5. Monitoring and Trending, GALL states, "The effects of corrosion of the aboveground External surface are detectable by visual techniques.

Based on operating experience, plant system walkdowis during each outage provide for timely detection of aging effects. The effects of corrosion of the underground external surface are detectable by thickness measurement of the tank bottom and are monitored and trended if significant material loss is detected." Question:

What is the schedule of plant system walkdowns by OCGS and is the OCGS schedule consistent with the GALL recommendation?

Response: The new Oyster Creek Aboveground Outdoor Tank aging management inspection program is based on industry and site specific operating experience and guidance for criteria and frequency.

The program utilizes structured inspections designed to applicable aging effects in place of system walkdowns each outage. The initial frequency will be inspections every five years. This is recognized as an exception to NUREG-1801.

This is a new exception not previously identified in the LRA.The following discussion is extracted from PBD-AMP-B.1.21 section 3.5 and is an exception to NUREG-801, element 5.The aboveground tanks external surfaces will be visually inspected for coating degradation and corrosion on uncoated aluminum by inspections at least once every five years. The new Oyster Creek Aboveground Outdoor Tanks aging management program will incorporate tank inspections in place of system walkdowns.

Inspection frequency is determined based on industry recommendations and specific tank service.(

Reference:

4.3.1) This is consistent with the practical life of external coatings (

Reference:

4.2.2, Section 5.2.6) and the industry application of structures monitoring programs in response to the Maintenance Rule (

Reference:

4.2.5). Refer to Exceptions to NUREG-1801, Element 5 discussion below for additional technical basis.The effects of corrosion of the Diesel Generator Fuel Oil Tank bottom external surface (mounted on concrete) and the condensate storage and the Fire Protection Water Storage Tanks bottom external surfaces (exposed to soil) are detectable by thickness measurement of the tank bottom. Initial thickness measurements will be compared to design requirements.

The results of these inspections are monitored and trended if significant material loss is detected such that component intended function is ensured.Exceptions to NUREG-1801, Element 5: The program takes exception to the inspection frequency during each outage specified in NUREG-1 801 Rev.I XI.M29, Aboveground Steel Tanks, for monitoring external surfaces of tank surfaces.

The specified frequency by the Oyster Creek program is every 5 years. Technical basis for this exception is as fo'lows.

Enclosure Page 10 of 39* The frequency of 5 years specified for monitoring of exterior surfaces of tanks is consistent with the frequency specified for exterior surfaces of supporting structures.

The 5 year frequency is consistent with industry guidelines and has proven effective in detecting loss of material due to corrosion, and change in material properties of structural elastomer on exterior surfaces of structures.

Consequently this frequency will also be effective for detecting loss of material and change in material properties on exterior surfaces of tank before an intended function is impacted.* Tank components subject to outdoor air are constructed from stainless steel or aluminum, which are not susceptible to accelerated corrosion, or carbon steel components protected by protective coatings such as galvanizing or painting.

Plant Operating Experience indicates that monitoring of exterior surfaces of components made of these materials and protective coatings on a frequency of 5 years provides reasonable assurance that loss of material will be detected before an intended function is affected.-Studies by EPRI (

Reference:

4.2.6, Fig. 4.1-1) provides corrosion rate curve for carbon steels. This curve was constructed from 55 individual tests representing at least five different steels and six different test locations and environments.

The curve shows 0.926 mils per year thickness loss during the first 1 1/2 years, decreasing to 0.21 mils per year after 15 1/2 years. EPRI also conducted corrosion tests of ASTM A-36 structural steel at four nuclear plants located in Elma and Richland, Washington; and Midland, Michigan.The tests were conducted for up to 24 months. EPRI concluded that based on the test results the corrosion rate is 0.5 rnils per year. If the corrosion rate is conservatively taken as 0.926 mils per year, then the loss of material projected for 5 years is less than 5 mils. This loss of material is insignificant and will not impact the intended function of mechanical components (

References:

4.2.6, 4.2.7).Comparison and Evaluation

==

Conclusion:==

This element is consistent with exceptions with NUREG-1801 Rev. 1 XL.M29, Aboveground Steel Tanks, for monitoring external surfaces of tanks. The specified frequency by the Oyster Creek program is eveiy 5 years; while XL.M29 requires a frequency of each outage. Technical basis for this exception is that, based on plant specific operating experience and industry experience, the 5-year frequency is adequate to provide reasonable assurance that aging effects will be detected and corrected before a loss of an intended function.References are included in PBD-AMP-B.1.21 notebook.

Enclosure Page 11 of 39 Item No AMP-188 Topic: Coatings Question: P. 7 of the PBD states in the Summary of Enhancements to NUREG-1801:

The inspection of Service Level I and Service Level II protective coatings that are credited for mitigating corrosion on interior surfaces of the Torus shell and vent system, and, on exterior surfaces of the Drywell shell in the area of the sandbed region, will be consistent with ASME Section Xl, Subsection IWE requirements.

Please clarify exactly what this enhancement entails. What changes are necessary to make the coating program consistent with ASME Section Xl, Subsection IWE requirements.

Response: The requirements for coating inspections are included in the following Oyster Creek specifications:

1. The inspection requirements for Service Level I protective coatings that are credited for mitigating corrosion on interior surfaces of the Torus shell and vent system are included in SP-1302-52-120,"Specification for Inspection and Localized Repair of the Torus and Vent System Coating" 2. The inspection requirements for Service Level II protective coatings that are credited for mitigating corrosion on exterior surfaces of the Drywell shell in the area of the sandbed region are included in IS-328227-004, "Functional Requirements for Drywell Containment Vessel Thickness Examination" These specifications do not currently invoke all of the requirements of ASME Section Xl, Subsection IWE.The following requirements will be included in these inspection specifications:

1. Torus and vent system internal coating inspections will be per Examination Category E-A and will require VT-3 visual examinations per IWE-3510.2.

a. The inspected area shall be examined (as a minimum) for evidence of flaking, blistering, peelirg, discoloration, and other signs of distress.b. Areas that are suspect shall be dispositioned by engineering evaluation or corrected by repair or eplacement in accordance with IWE-3122.c. Supplemental examinations in accordance with IWE-3200 shall be performed when specified as a result of engineering evaluation.

2. Sandbecl Region external coating inspections will be per Examination Category E-C (augmented examination) and will require VT-1 visual examinations per IWE-3412.1.

a. The inspected area shall be examined (as a minimum) for evidence of flaking, blistering, peeling, discoloration, and other signs of distress.b. Areas that are suspect shall be dispositioned by engineering evaluation or corrected by repair or replacement in accordance with IWE-3122.c. Supplemental examinations in accordance with IWE-3200 shall be performed when specified Es a result of engineering evaluation.

Enclosure Page 12 of 39 Item No AMP-1 90 Topic: ASME Seclion Xi Subsection IWB IWC IWD Ouestion: (Audit2 B.1.1-12):

The discussion of enhancements for OCGS AMP B.1.1 in the LRA states that monitoring activities for the isolation condenser that are recommended in NUREG-1801 will be added to the existing OCGS program. The Program Basis Document for OCGS AMP B.1.1 (PBD-AMP-B.1.01) identifies the enhancement in Section 2.4, Summary of Enhancements to NUREG-1 801; however, it does not identify the program elements to which It applies. Please identify the program elements to which this the stated enhancement applies.Response: The enhancement to OCGS AMP B.1.1 consisting of activities to monitor temperature and radioactivity of the isolation condenser shell side water, eddy current testing of the tubes, and inspections (VT or UT) of the channel head and tube sheets, with verification of effectiveness of the program through monitoring and trending of results, is listed in the PBD document under section 2.0, Program Description.

This is in response to the statement in the NUREG-1801 program XI.M1 Program Description section which says that in certain cases, the ASME inservice inspection program is to be augmented to manage effects of aging for license renewal and is so identified in the GALL report. The GALL specification for the augmented isolation condenser inspection activities is contained in GALL line item R-1 5 in September 2005 Revision 1 NUREG-1801.

The PBD document will be revised to also list this enhancement in Element 1, Scope of Program, Element 3, Parameters Monitored or Inspected, and Element 5, Monitoring and Trending.

Enclosure Page 13 of 39 Item No AMP-192 Topic: Fuel Oil Chemistry Ouestion: (Audit2-B.1.22-11):

The first exception to NUREG-1801 in OCGS AMP B.1.22 states that multilevel sampling, tank bottom sampling, draining, cleaning and internal inspection of the EDG day tanks are not routinely performed at Oyster Creek. The design of the EDG day tanks does not provide the capability for sampling of the tanks. Please provide the following information related to this exception:

a) Please provide additional information to justify why these tanks cannot be sampled, drained, cleaned, or inspected.

b) Part of the justification for this exception is that the EDG day tanks are supplied directly from the EDG fuel storage tank, which is routinely sampled and analyzed.

Section 3.10 of the Program Basis Document for this AMP (PBD..AMP-B.1.22) discusses operating experience in which a problem with increasing levels of water and sediment were experienced with the bottom samples and all-level samples from the EDG storage tank.Please 1) discuss the impact of this operating experience on the aforementioned exception noted for this AMP. Specifically, since a problem was identified with increasing water and sediment concentrations in the EDG fuel oil storage tank, discuss what evidence exists to assure that this increase in contaminants did not cause a current or impending problem in the EDG day tanks that has not yet been identified since these tanks are neither monitored nor inspected;

2) Discuss how the lack of future monitoring and inspecting of the EDG day tanks can be justified based upon this operating experience, and 3) Provide justification for not performing a one-time inspection of the EDG day tanks.Response: The first exception to NUREG-1801 in OCGS AMP B.1.22 states that multilevel sampling, tank bottom sampling, draining, cleaning and internal inspection of the EDG day tanks are not routinely performed at Oyster Creek.a) The tanks are not equipped with sampling capability and periodic sampling will not be done for th a day tanks. However, the day tanks will be internally inspected (one time) to confirm the absence of aging effects.Visual inspection will be performed.

Further inspections will be performed to quantify the degradation should there be any evidence of corrosion or pitting observed during the visual inspection.

b) Part of the justification for this exception is that the EDG day tanks are supplied directly from the EDG fuel storage tank, which is routinely sampled and analyzed.

1) The Operating Experience discussed in Section 3.10 of the Program Basis Document, which is further discussed in Request No.: AMP-191, identifies that the increased trend in water and sediment was attributed to long-term accumulation.

Prior to this 2003 event, Oyster Creek did not have in place recurring tasks to periodically drain accumulated water and sediment from the bottom of fuel oil storage tanks. Current Oyster Creek practice includes a quarterly periodic recurring tEsk to drain accumulated water and sediment from the bottom of the EDG Fuel Storage Tank. The EDG Fuel Storage tank is also periodically drained, cleaned, and internally inspected every 10 years and is periodically tested for water and sediment (bottom samples tested monthly; multilevel samples tested weekly and following transfer from the Main Fuel Oil Storage tank). Based on these current practices, which in part were developed as corrective actions to the 2003 event discussed above, and the fact that all sample results from that event were within specification, which is < or equal to 0.05 % water and sediment, current or Enclosure Page 14 of 39 impending problems in the EDG day tanks are not expected;

2) Based on the current practices discussed above, and based on the rationale provided in PBD-AMP-B.1.22 for the subject exception, the lack of periodic monitoring and inspection of the EDG day tanks during the extended period of operation isjustified;

3) The effectiveness of fuel oil practices on maintaining the intended function of the EDG day tanks will be confirmed prior to entering the period of extended operation.

The day tanks will be internally inspected (one time) to confirm the absence of aging effects. Visual inspection will be performed.

Further inspections will be performed to quantify the degradation should there be any evidence of corrosion or pitting observed during the visual inspection.

Enclosure Page 15 of 39 Item No AMP-197 Topic: BWR SCC Revised as 278 Ouestion: (BWR SCC).THIS QUESTION HAS BEEN REVISED ORIGINAL QUESTION"GALL requires the carbon content and ferrite content screening criteria, as stated in the GL 88-01, lo be applied to both component and weld materials, including CASS. The PBD (pg. 11 of 27) indicates that OCGS is currently applying these criteria to new and replacement components and weld materials.

However, the OCGS PBD adds a new enhancement to apply the screening criteria to all new and replacement SS components in order to be consistent with GALL. Also, it is stated in the PBD (pg. 20) that numerous; piping sections were replaced in conformance with the GL requirements. (a) Please discuss the screening criteria used at the time of these piping section replacements in response to GL 88-01.REVISED QUESTION (a) GALL requires the carbon content and ferrite content screening criteria, as stated in the GL 88-01, to be applied to both component and weld materials, including CASS. The PBD (pg. 11 of 27) indicates that OCGS is currently applying these criteria to new and replacement components and weld materials.

However, the OCGS PBD adds a new enhancement to apply the screening criteria to all new and replacement SS components in order to be consistent with GALL. Please explain why this enhancement is needed when OCGS has already been using the same criteria since the issuance of the GL 88-01.(b) The OCGS LRA description for the BWR Stress Corrosion Cracking program (AMP B.1.7) does not include any enhancements.

Please also discuss how the new enhancement discussed above will be documented as part of the LRA.Response: a) Of the original welds that were in the scope of GL 88-01, IGSCC was detected in 40 welds. Various piping replacements were performed in accordance with GL 88-01 in 13R. This resulted in a remaining 11 welds that were in service with indications of IGSCC. Nine were repaired with full structural overlays.

Two Reactor Recirculation system welds, which were both stress improved before initial inspections determined indication of IGSCC, remained in service without repair. However, subsequent to implementation of the NRC approved Performance Demonstration Initiative (PDI), inspections performed in 2002 and 2004 using the improved PDI examination technique determined these welds did not exhibit any indication of IGSCC. Oyster Creek, therefore, does not currently have any indication of IGSCC.Oyster Creek performed the replacements in 13R, as discussed above, in accordance with GL 88-01.However these replacements were performed as part of the implementation of GL 88-01 and it was determined that the current day documentation of the GL 88-01 commitments within the BWR Stress Corrosion Cracking Program were not to the same consistency as other program documentation.

Therefore, Oyster Creek felt that enhancing the program to include specific GL 88-01 wording in the line specifications, to ensure that the GL 88-01 requirements would be clear for each system within the scope of LR, would be beneficial.

b) This change will be submitted as a supplement to the LRA. Reference LRCR (license renewal change request) #2:48. A copy of LRCR was provided to Mano Subudhi during the 1pm breakout session or 1/25/06.

Enclosure Page 16 of 39 Item No AMP-202 Topic: Fire Water System Ouestion: 1. The LRA and FSAR Supplement state that prior to the period of extended operation, the program will be enhanced to include visual inspection of the redundant fire water storage tank heater during tank internal inspections.

PBD AMP B.1.20, Section 2.4 states that the Oyster Creek Fire Water System aging management program will be enhanced to include visual inspection of the water storage tank heater pressure boundary components during the periodic tank internal inspection.

This enhancement does not appear to be identified

/ discussed in Section 3.0 (comparison to individual GALL Elements).

Please clarify.2. NFPA 25 (1998 Edition) Section 2-3.1.1 or Section 5.3.1.1.1 (2002 Edition) directs replacement or representative sampling and field service testing of sprinklers that have been in place for 50 years. What is the starting point of the 50-year clock? Is it the date the fire system is initially pressurized and place in service? Is, there documentation for initial date of service for all the sprinklers, even those going back to the original insl:allation?

3. NFPA 25 is not on the list of codes and standards used in the design and installation of the fire protection system. NFPA 25 needs to be identified in the FSAR regarding its role as guidance standard for the testing and maintenance of sprinklers during the period of extended operation.

4. What administrative controls are used to track program enhancement commitments, procedure development, and activities, such as the 50 year sprinkler inspection commitment, that will not commence until well into the period of extended operation?

Response: 1. PBD-AMP-B.1.20 will be revised to include this enhancement in the Program Basis Document Section 3.1, Program Scope.2. Oyster C:reek construction was complete and operation began in April 1969. The initial plant con:;truction period was approximately 4 years, so the earliest date for sprinkler installations would be early to mid 1965.In accordance with NFPA standards, sprinkler head sampling is recommended after 50 years in service, with additional sampling at 10-year intervals thereafter.

The beginning of the 50-year clock will conservatively be established as January 1, 1965. Sprinkler head sample testing will therefore commence on or before Januaryl, 2015.3. The commitment to perform sprinkler head inspections in accordance with NFPA 25 is clearly identified in the LRA Appendix A UFSAR Supplement for the Fire Water System aging management program. It is not necessary to make conforming changes to other UFSAR sections to reflect this commitment.

4. Commitments are tracked in the Passport commitment tracking system, which includes automatic tracking and reporting of required activity due dates.

Enclosure Page 17 of 39 Itenm No AMP-209 Topic: IWE Ouestion: P. 17 of the! PBD states: As discussed with NRC Staff during the AMP audit, Oyster Creek will perform one-time UT thickness measurements of the drywell shell, in the sand bed region, to confirm that the protective coating is effective.

The UT measurements will be taken from inside the drywell at the same or approximate locations measured in 1996. This constitutes a new commitment that will implemented prior to entering the period of extended operation.

Has this been added to the scope of the One Time Inspection program? How will this commitment be tracked and implemented?

Are the locations selected for one-time inspection those that had the minimum remaining thickness based on prior UT results? If not, explain why the selected locations are adequate.

What steps will be taken if the current conclusion, that corrosion has been arrested, is not confirmed by the one-time inspection?

Also, please discuss the scope of the current coating inspection program and the LR commitment.

What % of the total circumference is inspected during each inspection?

How many years and how many inspections does it take to complete a 360 degree inspection of the sandbed region? Has a complete 360 degree inspection been completed yet? How many will be completed during the LR period?Response: No, the One-Time inspection of the sand bed region commitment has not been added to One-Time Inspection.

As discussed with NRC Staff on 1/26/2006, Oyster Creek will perform periodic UT inspections during the period of extended operation instead of One-Time inspection.

The initial UT inspections will occur prior to entering the period of extended operation and every 10 years thereafter.

Refer to AMP Audit Question No. 141 for additional details. This revised commitment will be tracked in accordance with Oyster Creek commitment tracking process. Additionally the commitment will be included in a revision to Appendix A.5 Commitment List, item #27, which will be submitted to the NRC and incorporated in the UFSAR Supplement.

Implementation of the commitment will be through the Oyster Creek ASME Section IX, Subsection IWE.The locations selected for UT measurements are the same as those inspected using UT measurements in 1996 and include the thinnest measured area. If the current conclusion that corrosion has been arrested is not confirmed by UT measurements taken prior to entering the period of extended operation, Oyster Creek is committed to take corrective actions defined in response to NRC Question #AMP-357.Protective coatings on the exterior surfaces of the drywell shell in the sand bed region are monitored in accordance with the Protective Coating Monitoring and Maintenance Program (B.1.33).

The current program requires visual inspection of the coating in accordance with engineering specification IS-328227-004.

Inspection criteria is not specifically provided by the specification.

However inspections are performed by individuals qualified to perform coating inspections.

Acceptance criteria provided in the specification is that any identified coating defects shall be submitted for engineering evaluation.

The inspection frequency is every other refueling outage.As discussed with NRC Staff, the existing Protective Coating Monitoring and Maintenance aging Enclosure Page 18 of 39 management program does not currently invoke the requirements of ASME Section Xl, Subsection IWE.Oyster Creek is committed to enhancing the program to incorporate coated surfaces inspection requirements specified in ASME Section Xl, Subsection IWE. In response to NRC Question AMP-188, Oyster Creek provided specific enhancements that will be made to the program as follows: Sand bed Region external coating inspections will be per Examination Category E-C (augmented examination) and will require VT-1 visual examinations per IWE-3412.1.

a. The inspected area shall be examined (as a minimum) for evidence of flaking, blistering, peeling, discoloration, and other signs of distress.b. Areas that are suspect shall be dispositioned by engineering evaluation or corrected by repair or replacement in accordance with IWE-3122.c. Supplemental examinations in accordance with IWE-3200 shall be performed when specified as a result of engineering evaluation.

The coated surface of the drywell shell in the sand bed region is divided into 10 bays that constitute 360 degrees. The current program requires inspection of coatings in at least 2 bays every other refueling outage.Certain bays were considered critical and have been inspected more than once. Inspection of 5 out of 10 bays (50%, has been completed to date.For license renewal Oyster Creek is committed to inspect the remaining 5 bays prior to entering the period of extended operation.

This will result in a complete (100%) coating inspection of all the 10 bays (360 degree)prior to entering the period of extended operation.

Oyster Creek is also committed to inspect the coating in accordance with ASME Section Xl, Subsection IWE. Thus inspection of 100% of the coating will be completed during each Containment ISI 10-Year Interval.

Inspections will be conducted every other refueling outage during which at least 3 bays (30% of the coating min) will be examined.

We therefore expect to inspect 100% of the coating twice during the period of extended operation.

The inspections will be conducted in accordance with the enhanced Protective Coating Monitoring and Maintenance Program (B.1.33), including enhancements discussed in NRC Audit Question AMP-188.General revision of the response to add and clarify commitments. (AMO 4/2/06)

Enclosure Page 19 of 39 Itent No AMP-224 Topic: Inaccessible Med. Voltage Cables not subj. to EQ Ouestion: Element # 5 -Confirm whether the test results are trended to provide additional information regarding cable degradation.

Response: Commitment to a specific testing methodology has not yet been made since Oyster Creek is pursuing, but has not yet obtained, industry endorsement of a preferred methodology.

On-going test results from the current Oyster Creek medium voltage cable testing program are being trended. Trending of test results will continue through the period of extended operation.

The PBD for the B.1.36 aging management program will be revised via LRCR to add trending of test results through the period of extended operation.

Enclosure Page 20 of 39 Item No AMP-265 Topic: One Time Inspection Ouestion: AMP-TBD (Audit2 B.1.24-9):

The OCGS Inspection Sample Basis document for the one-time inspection, dated 08/16/2005, states that the one-time inspection sample size for stress corrosion cracking will include one (1) stainless steel pipe section in a stagnant or low flow area (>140F). The sample size for loss of material includes 2 carbon steel pipe sections in some cases, and 3 carbon steel pipe sections in other cases. Please provide the rational and justification for selecting the number of samples for each aging effect.In particular, discuss why one sample of stainless steel piping is considered to be an adequate population for detecting stress corrosion cracking.

Include a discussion of how Oyster Creek operating experience was factored into the number of samples selected for each application.

Response: The OCGS Inspection Sample Basis document for the one-time inspection, dated 08/16/2005, states that the one-time inspection program will be used to verify the effectiveness of the Water Chemistry program to manage stress corrosion cracking.

The one-time inspection program sample size for stress corrosion cracking will include one (1) stainless steel pipe section in a stagnant or low flow area (>140F). The selected sample for one-time inspections for stress corrosion cracking currently includes:-One (1) stainless steel pipe section in a stagnant or low flow area (> 140 F) in the Reactor Water Cleanup System. The one-time inspection for cracking will be by nondestructive examination (UT). Examples of acceptable sample locations include:-Cleanup Aux. Pump discharge line between V-16-13 and the 6" RWCU main process line.-One (1) stainless steel pipe section in a stagnant or low flow area (> 140 F) in the Isolation Condenser System. The one-time inspection for cracking will be by nondestructive examination (UT). Examples of acceptable sample locations include:-12" or *16" non-class I Isolation Condenser steam inlet piping. Portions of the 8" or 10" condensate return lines up to the normally closed isolation condenser condensate return valves can also be inspected if> 140 F.The selected sample for one-time inspections for stress corrosion cracking will be revised as follows:-Two (2) stainless steel pipe sections in a stagnant or low flow area (> 140 F) in the Reactor Water Cleanup System. The one-time inspection for cracking will be by nondestructive examination (UT). Examples of acceptable sample locations include:-Cleanup Aux. Pump discharge line between V-16-13 and the 6" RWCU main process line.-Two (2) stainless steel pipe sections in a stagnant or low flow area (> 140 F) in the Isolation Condenser System. The one-time inspection for cracking will be by nondestructive examination (UT). Examples of Enclosure Page 21 of 39 acceptable sample locations include:-12" or 16" non-class 1 Isolation Condenser steam inlet piping. Portions of the 8" or 10" condensate return lines up to the normally closed isolation condenser condensate return valves can also be inspected if> 140 F.The one-time inspections performed for the non-class 1 portions of the Isolation Condenser System to verify the effectiveness of the water chemistry program to manage cracking are different inspections from those inspections performed in conjunction with ASME Sections Xl, Water Chemistry, and the BWR Stress Corrosion Cracking aging management programs for RCPB piping, piping components, and piping elements.The one-time inspections specified for the non-RCPB portions of the Reactor Water Cleanup Systern are inspections beyond those required by the BWR Reactor Water Cleanup System aging management program.LRCR# 259 will track changes associated with this question.

It is noted that LRCR# 259 will also be used to convert the "Inspection Sample Basis, Oyster Creek License Renewal Project" document into a controlled project Position Paper with associated review and approval signatures (reference AMP-263).

Enclosure Page 22 of 39 Item No AMP-338 Topic: Ouestion: The existing wording in LRA A. 1.36 and B.1.36 suggests that polarization index can be substituted for partial discharge test. Since polarization index test alone is not sufficient to detect aging effects of cable, will this be clarified in the LRA?Response: Current test methodologies at Oyster Creek implement polarization index test as part of step voltage and meggar tests. It should be noted that Oyster Creek does not currently nor plan to use polarization index testing as the lone condition monitoring test in its B.1.36 aging management program.LRCR 273 will delete polarization index testing from the Appendix A Table A.05 commitment

1. 36, Appendix A, section A.1.36, Appendix B section B.1.36 and PBD-AMP-B.1.36.

Enclosure Page 23 of 39 Itent No AMP-359 Topic: Lubricating Oil Analysis Program -FRCT (AMP B.1.39)Ouestion: This question was received from Donnie Ashley, NRC Project Manager on 3/14/06 as a draft RAI. On 3/16/06 it was agreed that it would be addressed in the Q&A database since it originates from the audit (Roy Matthew).

Subsequently included in 3/17/06 email from Donnie Ashley to George Beck The Lubricating Oil Analysis Program -FRCT (OCGS AMP B.1.39) takes exception to the GALL Report requirement to monitor flash point.The basis provided for exceptions to GALL, Element 3 (Parameters Monitored or Inspected) is not valid since the Flash Point of an industrial lubricant is an important test to determine if light-end hydrocarbons are getting into the oil through seal leaks or other means. It is an effective way to monitor seal performance in light end hydro-carbon compressors.

Low Flash Points pose a safety hazard in the event of component failure that can generate heat above the flash point of the oil, such as bearing failure.Please justify the reason for not monitoring the flash point of lubricating oil at the FRCT and why this, exception is acceptable to manage the effects of aging for which it is credited.Response: The Lubricating Oil Analysis Program -FRCT (PBD-AMP-1.39) will be revised to include measurement of flash point.(This is consistent with PBD-AMP-B.2.02 Lubricating Oil Monitoring Activities)

Enclosure Page 24 of 39 Itent N~o AMP-360 Topic: PBD-AMP-B.2.2 Lubricating Oil Monitoring Activities Ouestion: This question was received in an email from Donnie Ashley, NRC Project Manager, to George Beck, dated 3/17/06.PBD-AMP-B.2.2, uLubricating Oil Monitoring Activities," Element 3 states that oil analysis guidelines will be enhanced to include measurement of flash point for diesel engine lubricating oil. This is a new enhancement based on the reconciliation of this aging management program from the draft January 2005 NUREG-1800, Rev. I to the approved September 2005 NUREG-1801, Rev. 1. This enhancement is not identified in OCGS LRA B.2.2. Is the LRA supplemented to reflect this?Respon. c: This enhancement is addressed in the "Summary of Reconciliation of OC LRA to September 2005 Revision 1 NUREG-1800 and NUREG-1801" transmitted to the NRC on March 30, 2006 (Letter No. 2130-06-20293).

This is an addition to the LRA Table A.5 License Renewal Commitment List Item No. 38.

Enclosure Page 25 of 39 Item,, No AMP-361 Topic: PBD-AMP-B.1.12 Bolting Integrity Outestion:

This question was received in an email from Donnie Ashley, NRC Project Manager, to George Beck, dated 3/17/06.PBD -AMP- B.1.12, "Bolting Integrity" identifies an enhancement to NUREG-1801 for elements 1, 2, and 7.This enhancement is not identified in OCGS LRA B1.12. Is the LRA supplemented to reflect this?Responise:

During preparation of PBD we identified the need for enhancement.

LRCR-242 was generated to revise Appendix A and B for Bolting Integrity, which contains the enhancement to include reference to EPRI TR-104213a in the site procedure.

Enclosure Page 26 of 39 DIent No AMR-1 00 Topic: Rx Internals-TLAAs Ouestio In Table 3.1.2.1.4, the applicant credits TLAA to manage fatigue damage for RV internal components.

Please confirm that TLAA for those items do exist. If not, please explain how the applicant is going to manage fatigue damage. Note: The above question applies to other Tables also. Please ensure that all the Table 2 items which credit TLAA do have TLAA. For examples, In Table 3.1.2.1.5, Nozzle thermal sleeves are credited TLAA.Response: The use of TLAA in Section 3 has been reviewed.

The use of TLAA as an aging management program in LRA Table 3.1.2.1.4 "Reactor Internals" and Table 3.1.2.1.5 "Reactor Pressure Vessel" indicates that the current licensing basis was reviewed for TLAAs and the fatigue analysis was evaluated where one existed for that component.

However, several components for which TLAA was identified as the aging management program for the cumulative fatigue aging effect do not have fatigue analyses.

These components include the reactor internals and the CRD and Feedwater nozzle thermal sleeves. In the absence of a fatigue analysis for these components, the effects of cumulative fatigue are managed by other aging management programs.For example, cumulative fatigue effects in reactor internal components are managed by the "BWR \Vessel Internals" aging management program. Similarly, the BWR Feedwater Nozzle and BWR CRD Return Line Nozzle aging management programs manage the effects of cumulative fatigue in the thermal sleeves for the Feedwater and CRD Return Line nozzles, respectively.

LRA Table 3.1.2.1.4 "Reactor Internals" and Table 3.1.2.1.5 "Reactor Pressure Vessel" (which includes the CRD and Feedwater nozzle thermal sleeves) will be revised to delete the TLAA aging management program for components where a TLAA does not exist. The appropriate aging management program will be identified with an "E" Industry Standard note and a plant specific note stating "There is no fatigue analysis for this component.

The aging effect of cumulative fatigue is managed by the BWR Vessel Internals aging management program".

Similarly for the thermal sleeves the note will read: "There is no fatigue analysis for this component.

The aging effect of cumulative fatigue is managed by the BWR Feedwater Nozzle (or BWR CRD Return Line Nozzle, as applicable) aging management program".

Enclosure Page 27 of 39 Item ANo AMR-171 Topic: Loss of Material Ouestion: The Discussion indicates a larger scope for managing loss of material than the scope identified in the AMP description (B.1.33).

Please clearly define the complete scope for which this AMP is credited, for managing loss of material.Response: LRA REQUIREMENTS:

LRA Table 3.5.1 Item Number 3.5.1-15 states: "The Protective Coating Monitoring and Maintenance!

Program, 6.1.33 will be used to manage loss of material of internal surfaces of the primary containment steel elements, including the suppression chamber surfaces immersed in treated water, exterior surfaces of the vent lines, and on the exterior surfaces of the drywell in the former sand bed region. The program is in addition to ASME Section Xi, Subsection IWE, 10 CFR Part 50 Appendix J, and TLAA, as applicable." Structures and/or components and environments "rolled-up" into LRA Table 3.5.1 Item Number 3.5.1-15 include (reference LRA Table 3.5.2.1.1 for Primary Containment):-Access Hatch Covers -Containment Atmosphere (Internal)-Downcomers

-Containment Atmosphere

• Drywell Penetration Sleeves -Containment Atmosphere (Internal)-Drywell Shell -Containment Atmosphere (Internal) and Indoor Air (External)-Personnel Airlock/Equipment Hatch -Containment Atmosphere (Internal)

Suppression Chamber Penetrations

-Containment Atmosphere (Internal)-Suppression Chamber Ring Girders -Containment Atmosphere (External)-Suppression Chamber Shell -Containment Atmosphere (Internal)-Vent Line, and Vent Header -Containment Atmosphere (Internal) and Indoor Air (External)

Structures and/or components in immersed environments (non-GALL items) are also managed by the Protective Coating Monitoring and Maintenance Program, B.1.33 and include:-Downcomers-Suppression Chamber Ring Girders Suppression Chamber Penetrations-Suppression Chamber Shell AMP B.1.33 states: "The Protective Coating Monitoring and Maintenance Program provides for aging management of Service Level I coatings inside the primary containment and Service Level II coatings for the external drwell shell in the area of the sandbed region. Service Level I coatings are used in areas where the coating failure could adversely affect the operation of post-accident fluid systems and thereby impair safe shutdown." "Service Level II coatings provide corrosion protection and decontaminability in those areas outside of the primary containment that are subject to radiation exposure and radionuclide contamination.

The Protective Coating Monitoring and Maintenance Program provides for visual inspections, assessment, and repairs for any condition that adversely affects the ability of Service Level I coatings, or sandbed region Enclosure Page 28 of 39 Service Level II coatings, to function as intended." SERVICE LEVEL I COATING EVALUATION:

Not all Service Level I protective coatings inside the Primary Containment are credited for corrosion protection.

Service Level 1 coatings are not credited for corrosion protection for the drywell shell above the sandbed region. ASME Section Xl, Subsection IWE (B.1.27) and 10 CFR Part 50, Appendix J (B.1.29) are credited for managing loss of material in the drywell shell above the sandbed region during the pericid of extended operation.

In addition, an analysis has been performed which demonstrates that the upper portion of the drywell vessel will meet ASME code requirements for the remaining life of the plant based on corrosion rates (reference UFSAR Section 3.8.2.8).

The corrosion of the drywell shell above the sandbed region is considered a TLAA and is further described in LRA Section 4.7.2.Service Level I coatings are credited for corrosion protection for the immersion zone of the torus, for torus internal structures, for downcomers, and for the vent system which previously had been thinned by corrosion and repaired (reference UFSAR Section 3.8.2.6.2 and Specification OCIS 328001-001).

Although the air in the torus vapor space is replaced with nitrogen and the oxygen concentration is maintained below 4% during power operation, the Service Level I coating in the torus vapor space is credited for corrosion protection.

Based on the above discussions, the following clarification is provided.

The Protective Coating Monitoring and Maintenance Program is not used to manage loss of material for the Drywell Shell and component types including Access Hatch Covers, Drywell Penetration Sleeves, and Personnel Airlock/Equipment Hatch exposed to a Containment Atmosphere (Internal) environment.

Accordingly, LRA Table 3.5.2.1.1 for the Primary Containment will be revised to delete the Protective Coating Monitoring and Maintenance p ogram (B.1.33) from these component types exposed to a containment atmosphere environment.

Corrosion in the Drywell Shell, Access Hatch Covers, Drywell Penetration Sleeves, and Personnel Airlock/Equipment Hatch exposed to a Containment Atmosphere (Internal) environment is managed by the ASME Section Xl, Subsection IWE (B.1.27) and the 10 CFR Part 50, Appendix J (B.1.29) aging management programs.

The corrosion of the drywell shell above the sandbed region is also considered a TLAA.Although not credited for providing corrosion protection for the Drywell Shell, Access Hatch Covers, Drywell Penetration Sleeves, and Personnel Airlock/Equipment Hatch, the Protective Coating Monitoring and Maintenance Program is credited for maintaining the LOCA qualification of the coating for the Drywell Shell, Access Hatch Covers, Drywell Penetration Sleeves, and Personnel Airlock/Equipment Hatch. As discussed in the response to Audit Question AMP-006, and, as discussed in Program Basis Document PBD-AM\AP-B.1.33, all Service Level I coatings in the Drywell, Torus, and Vent System are qualified for a LOCA environment.

Monitoring of Service Level I coatings to satisfy this requirement provides an added protection, though not required, against corrosion of the drywell shell.SERVICE LEVEL 11 COATING EVALUATION:

Service Level II coatings are credited for corrosion protection for the external drywell shell in the area of the sandbed region only (e.g., Drywell Shell exposed to a Indoor Air (External) environment).

Based on t'ne above discussions, the following clarification is provided.

The Protective Coating Monitoring and Maintenance Program is not used to manage corrosion for the Vent Line, and Vent Header exposed to an Indoor Air (External) environment.

Accordingly, LRA table 3.5.2.1.1 and Table 3.5.1 item 3.5.1-15 will be Enclosure Page 29 of 39 revised to delete the Protective Coating Monitoring and Maintenance program (B.1.33) from this component type exposed to an indoor air environment.

Corrosion in the Vent Line and Vent Header exposed tc an Indoor Air (External) environment is managed by the ASME Section Xi, Subsection IWE (B.1.27) and the 10 CFR Part 50, Appendix J (B.1.29) aging management programs.ATTACHMENTS:

1.UFSAR Section 3.8.2.8 2.UFSAR Section 3.8.2.6 3.Specification OCIS 328001-001, "Installation Specification for Torus Coating, Oyster Creek Nuclear Generating Station Pressure Suppression Chamber," Revision 0 Enclosure Page 30 of 39 Itent No AMR-248 Topic: Engineered Safety Features OQtestion:

3.3-3 Section 3.2.2.2.8.2 of the OCGS LRA, which addresses loss of material due to general, pitting and crevice corrosion in steel ducting closure bolting and piping in contact with treated water, states that the Oyster Creek Engineered Safety Features Systems have no carbon steel piping, piping components, or piping elements (internal surfaces) exposed to condensation, treated water, or air-indoor uncontrolled environments within the scope of license renewal. However, LRA section 3.2.2.2.8.1, which addresses loss of material due to general, pitting and crevice corrosion in aluminum and steel piping in contact with treated water, states that the Water Chemistry and the One-Time Inspection AMPs will be used to manage aging of carbon steel piping exposed to treated water. Please clarify this discrepancy.

Response: The Oyster Creek LRA used line item 3.2.1-10 (E-08) and associated further evaluation section 3.2.2.2.8.1 for steel piping in contact with treated water in the Engineered Safety Features (ESF) Systems. In the GALL, this line item invokes the Water Chemistry and a One-Time Inspection programs with further evaluation recommended and was the clearly applicable choice for managing aging effects in water-carrying process piping for the ESF systems. Line item 3.2.1-10 was only used for Oyster Creek as related item E-4() for steel closure bolting in the Standby Gas Treatment System. In the January 2005 draft GALL, this line item specifies a plant specific program for aging management.

The statement in the associated further evaluation section 3.2.2.2.8.2 for item 3.2.1-10 (that the ESF systems have no carbon steel piping, piping components, or piping elements (internal surfaces) exposed to condensation, treated water, or air-indoor uncontrolled environments) was made within the context of this line item's application to a wetted-air internal environment, and was not used for the steel piping lines of the ESF systems. "Treated Water" was included to match the SRP wording in section 3.2.2.2.8.2.

To correct this discrepancy, this statement will be revised in a supplement document to read as follows: The Oyster Creek Engineered Safety Features Systems have no steel piping, piping components, or piping elements (internal surfaces) exposed to condensation, treated water (in the form of condensation wetting the internal surface), or air-indoor uncontrolled environments.

Enclosure Page 31 of 39 Itent No AMR-255 Topic: Auxiliary Systems Ouestion: 3.3-6 Table! 3.3.2.1.41 of the OCGS LRA includes line items for brass and bronze valve bodies in the water treatment and distribution system that are exposed to treated water on the internal surface. The Selective Leaching of Materials AMP (B.1.25) is credited to manage selective leaching; however, loss of material due to pitting and crevice corrosion is not addressed.

Please clarify how loss of material due to pitting and crevice corrosion will be managed for these components.

Response: As a result of assembling the AMR Technical Basis Documents, it was discovered that the following line items need to be added to Table 3.3.2.1.41 to address how loss of material due to pitting and crevice corrosion will be managed for these components:

Valve Body -Leakage Boundary -Brass -Treated Water (Internal)

-Loss of Material -Water Chemistry (B.1.2)-VII.E4-8(AP-64) 3.3.1-38 Valve Body -Leakage Boundary -Brass -Treated Water (Internal)

-Loss of Material -One-Time Inspection (B.1.24) -VII.E4-8 (AP-64) 3.3.1-38 Valve Body -Leakage Boundary -Bronze -Treated Water (Internal)

-Loss of Material -Water Chemistry (B.1.2)-VII.E4-8(AP-64) 3.3.1-38 Valve Body -Leakage Boundary -Bronze -Treated Water (Internal)

-Loss of Material -One-Time Inspection (B.1.24) -VIl.E4-8 (AP-64) 3.3.1-38 The AMR Technical Basis Documents have been completed and will be given to the NRC auditors on-site on Monday, Feb 13 in both hard copy and electronic format. Reference OC-AMR-M-2.3.3.41, Water Treatment& Distributibn System.The above change is being tracked via LRCR #265 and will be submitted in a supplement to the LRA.

Enclosure Page 32 of 39 Iteun No AMR-258 Topic: Auxiliary Systems Ouestion: 3.3-9 In Table 3.3.1 of the OCGS LRA, line item 3.3.1-31 addresses loss of material due to pitting and crevice corrosion for copper alloy components exposed to treated water and closed cycle cooling water. The LRA states that the closed-cycle cooling water program (AMP B.1.14) alone will be used to manage this aging effect for components in the closed cycle cooling water environment.

Line items 3.3.1-39 and 3.3.1-42 address the same environment and aging effects for stainless steel; however, in these cases both the closed-cycle cooling water program and one-time inspection program are credited.

GALL recommends the closed-cycle cooling water program alone for all of the aforementioned cases. With regard to these AMRs, a) please explain the rational for concluding that a one-time inspection is needed to verify the effectiveness of the closed-cycle cooling water program for stainless steel components, but not for copper alloy components; and b) please clarify whether the OCGS closed-cycle cooling water program (AMP B.1.14)includes an inspection of stagnant flow areas and crevices, as recommended in GALL AMP XL.M21.Resp~onsc:

The question refers to line item 3.3.1-31.

This item should read 3.3.1-38.As stated in the draft January version of XL.M21, Closed Cycle Cooling Water System, the control of water chemistry does not preclude corrosion at locations of stagnant flow conditions.

For Oyster Creek, the One-Time Inspection program will be used to confirm the absence of aging effects in low flow or stagnant flow areas in closed cooling water systems (reference:

PBD-AMP-B.1.24 for One-Time Inspection and PBD-AMP-B.1.14 for Closed Cycle Cooling Water Systems).

The One-Time Inspection in low or stagnant flow areas has been applied to the component type of piping only.a) LRA Line Item 3.3.1-38 includes component types of piping components and piping elements (e.g., level glass, restricting orifice, thermowell, valve body, etc.) but does not include piping (inadvertently included in 3.3.1-38 Oyster Creek Discussion), therefore, One-Time Inspection was not applied in accordance with the Oyster Creek aging management review methodology.

The component type of piping was included in Line Items 3.3.1-39 and 3.3.1-42, therefore, One-Time Inspection was applied to confirm the absence of aging effects in low flow or stagnant flow areas in closed cooling water systems.b) The One-Time Inspection program will be used to confirm the absence of aging effects in low flow or stagnant flow areas in closed cooling water systems (reference:

PBD-AMP-B.1.24 for One-Time Inspection and PBD-AMP-B.1.14 for Closed Cycle Cooling Water Systems).

Enclosure Page 33 of 39 Item Nlo AMR-302 Topic: Reactor Building Closed Cooling Water System Ouestion: LRA Table 3.3.2.1.29 line items -Question:

For the RBCCW System, there are no aging effects shown for steel components in a containment atmosphere.

This is not consistent with the staff position presented in GALL Rev. 1.Response: Based on a review of operating experience, significant surface corrosion of carbon steel mechanical system components inside the drywell has not been observed, except that surface corrosion has been identified in the Reactor Building Closed Cooling Water (RBCCW) system piping and an RBCCW system valve inside the drywell. The RBCCW system is supplied with chilled water during outage periods, and therefore, uninsulated portions of Ihe system are subject to condensation and an air environment conducive to corrosion during outage operation.

The identified RBCCW system surface corrosion has been evaluated under the Oyster Creek corrective action program, and it was determined that the system function was not affected.

Wall thickness measurements indicate that the piping remains within nominal wall thickness specifications.

It is anticipated that periodic inspections of the uninsulated RBCCW piping inside the drywell will be required to monitor for additional RBCCW system corrosion due to surface condensation during outage periods.Therefore, based on this operating experience, external surface inspections of uninsulated RBCCW system carbon steel components within the drywell will be performed.

These inspections will be included in the Structures Monitoring Program aging management program for license renewal. LRCR # 261 has been initiated to process the necessary changes to license renewal documents to address this change.

Enclosure Page 34 of 39 Item Neo AMR-335 Topic: oumStion: U.In LRA Section 3.2.2.2, the applicant provides the basis for identifying those programs that warrant further evaluation for the Engineered Safety Features (ESF) systems. This section of the LRA does not address all material-environment-aging effect (MEA) combinations identified in the corresponding section in the SRP-LR.Please discuss the following MEA combinations as applicable to the ESF systems: a) Loss of material due to pitting and crevice corrosion in SS containment isolation piping, piping components, and piping elements exposed to treated water (SRP-LR Section 3.2.2.2.3.1).

Note that LRA Table 3.2.1-3 addresses SS piping, piping components, and piping elements exposed to treated water, and also discusses isolation condenser SS tubes and tube side components.

b) Loss of material due to pitting and crevice corrosion in SS piping, piping components, and piping elements exposed to treated water (SRP-LR Section 3.2.2.2.3.3).

Note that LRA Table 3.2.1-10 addresses CS and aluminum piping, piping components, and piping elements exposed to treated water.c) Loss of material due to pitting and crevice corrosion in SS piping, piping components, and piping elements exposed to lubricating oil (SRP-LR Section 3.2.2.2.3.4).

Note that LRA Table 3.2.1-37 addresses CS and copper alloy piping, piping components, and piping elements exposed to lubricating oil (no water pooling).Also, LRA Table 3.2.1-34 indicates no aging effect for SS piping, piping components, and piping elements exposed to lubricating oil consistent with GALL (is this true? See LRA Table 3.3.1-27).

d) Reduction in heat transfer due to fouling in CS, SS, and copper alloy HX tubes exposed to lubricating oil (SRP-LR Section 3.2.2.2.4.1).

e) Reduction in heat transfer due to fouling in SS HX tubes exposed to treated water on either side :SRP-LR Section 3.2.2.2.4.2).

Note that LRA Table 3.2.1-24 addresses SS HX tubes exposed to treated water, and credits the water chemistry program and the SRP-LR Table 3.2.1, item 10 requires both water chemistry and one time inspection AMPs.f) Loss of material due to general, pitting and crevice corrosion in CS piping, piping components, and piping elements (including containment isolation systems) exposed to treated water (SRP-LR Section 3.2.2.2.8.2).

g) Loss of material due to general, pitting and crevice corrosion, in CS piping, piping components, and piping elements exposed to lubricating oil (SRP-LR Section 3.2.2.2.8.3).

h) Loss of material due to MIC of external surfaces in buried CS (with or without coating or wrapping) piping, piping components, and piping elements exposed to treated water (SRP-LR Section 3.2.2.2.9).

Nole that LRA Section 3.2.2.2.8.3 (and LRA Table 3.2.1-12) addresses this aging effect due to general, pitting, and crevice corrosion buried in soil and identifies that no buried CS tanks in the ESF systems in the scope of LR.Also, SRP-LR requires demonstration of effectiveness of the buried piping inspection program (B.1.26).Response: A number of the material-environment-aging effect (MEA) combinations identified in the September 2005 Revision 1 SRP are new to that document and were not included in the January 2005 Draft SRP which was used in generating the Oyster Creek License Renewal Application (LRA). Other MEA combinations identified in the September 2005 Revision 1 SRP were also included in the January 2005 Draft SRP, but were not Enclosure Page 35 of 39 used in the Oyster Creek LRA, either because the MEA combination does not exist at Oyster Creek, or because an alternate Table 2 Related Item Number was used. The Oyster Creek License Renewal document, "Reconciliation of Program and Line Item Differences Between January 2005 Draft NUREG-1801 and September 2005 NUREG-1801 Revision 1", and the Oyster Creek "Roadmap" Excel table can provide information to correlate the September 2005 Revision 1 SRP with the Oyster Creek LRA.a. The September 2005 Revision I SRP changed line item E-33 to apply specifically to SS containment isolation piping in a treated water environment, and now specifies Water Chemistry and One-Time I ispection as the AMF's to be used, in lieu of a plant-specific program as specified in the January 2005 draft SRP. The Oyster Creek LRA specifies this same line item E-33 for SS piping and components in a treated waler environment, and lists the Water Chemistry and One-Time Inspection aging management programs, in accordance with the September 2005 Revision 1 SRP. Line Item EP-32 is also used in the Oyster Creek LRA for loss of material due to pitting and crevice corrosion in SS piping and components in containment isolation piping in a treated water environment.

This line item, which specified plant-specific programs in the January 2005 draft SRP and now specifies Water Chemistry and One-Time Inspection programs in the September 2005 Revision 1 SRP, is used at Oyster Creek with the aging management programs o1 Water Chemistry and One-Time Inspection, in accordance with the SRP. Line items E-33 and EP-32 are both addressed in Oyster Creek LRA Table 3.2.1-3 and Section 3.2.2.2.3.1.

The ASME Section XI ISI program is also applied as an additional program under EP-32 specifically for loss of material in the Isolation Condenser SS tubes. Reference LRA Section 3.2.2.2.3.1.

b. Loss of material due to pitting and crevice corrosion in SS piping, piping components, and piping elements in a treated water environment are addressed by Oyster Creek LRA line Item EP-32, Table 3.2.1-3, LRA Section 3.2.2.2.3.1.

c. Line items EP-45 and EP-51 addressed in the September 2005 Revision 1 SRP (SRP Section 3.2.2.2.3.4) are new line items not contained in the January 2005 draft SRP used in preparing the Oyster Creek LRA.This MEA combination is not present in ESF systems at Oyster Creek. The Oyster Creek LRA addresses loss of material in SS in a lubricating oil environment with line items AP-59 (LRA Section 3.3.2.2.12.2) and SP-38 (LRA Section 3.4.2.2.8).

For ESF systems, Oyster Creek LRA Table item 3.2.1-34 (EP-21) indicates no aging effect for SS piping, piping components, and piping elements in a lubricating oil environment.

This is consistent with the January 2005 draft SRP, Table 3.2-1 item 34 which indicates that for stainless steel piping, piping components, and piping elements exposed to lubricating oil, the Aging Effect/Mechanism is"None" and Aging Management Programs are "None". LRA Table 3.2.1, Item 3.2.1-34 will be revised in a supplement to state that the MEA is not applicable to the Oyster Creek ESF systems. Reference LRCR No.272 d. September 2005 Revision 1 SRP Section 3.2.2.2.4.1 addresses line items EP-40, EP-47, and EP-50, which are all new line items added to the September 2005 Revision 1 of the SRP and were not included in the January draft SRP. Consequently, these items were not used in the Oyster Creek LRA. This MEA combination is not present in ESF systems at Oyster Creek. The Oyster Creek LRA used the Lubribating Oil Monitoring Activities (B.2.2) program for reduction of heat transfer in aluminum heat exchanger fins, cast iron bearing cooler housings, and copper alloy heat exchanger tubes exposed to a lubricating oil environment in the EDG, FRBCCW, and Fire Protection Systems. The January 2005 draft SRP did not contain these MEA combinations, therefore plant-specific notes were applied to these line items.

Enclosure Page 36 of 39 e. Reference the Reconciliation document, Page 10, and Attachment

3. September 2005 Revision 1 SRP Section 3.2.2.2.4.2 addresses line item EP-34. This line item for stainless steel heat exchanger tubes in treated water, addressing reduction of heat transfer due to fouling, invoked the Water Chemistry program with "No" further evaluation required in the January 2005 draft GALL and has been changed in the September 2005 Revision 1 GALL to Water Chemistry and One-Time Inspection, with "Yes" for evaluation of aging effects. There are 2 instances of this line item being used in the Oyster Creek License Renewal Application, both in the Isolation Condenser system, for heat exchanger tubes, internal and external.

The Oyster Creek LRA will add two line items for one-time inspection of the internal and external surfaces of the isolation condenser tube for reduction of heat transfer due to fouling. These are new additions based on the reconciliation of the Oyster Creek LRA between the January 2005 draft GALL and the approved September 2005 Revision 1 GALL.f. Please reference the response to AMR-248 for a discussion of SRP Section 3.2.2.2.8.2.

For this MEA in the Oyster Creek ESF systems, the Oyster Creek LRA used line item 3.2.1-10 (E-08) and associated further evaluation section 3.2.2.2.8.1 for steel piping in contact with treated water in the Engineered Safety Features (ESF) Systems.g. September 2005 Revision I SRP Section 3.2.2.2.8.3 addresses line item EP-46. This is a new line item that was nct in the January 2005 draft SRP. This MEA combination is not present in ESF systems at Oyster Creek. The Oyster Creek LRA used line items AP-30 (3.3.1-16) and SP-25 (3.4.1-3) for carbon steel piping, piping components, and piping elements exposed to lubricating oil. Reference the Reconciliation document, Attachment 5 Item No. 6 for AP-30 (used in the following systems: Control Rod Drive, Misc. Floor and Eq. Drains, Reactor Recirculation, EDG, Station Blackout, RBCCW, RWCU, Fire Protection, and Service Water), and Attachment 5 Item No. 38 for SP-25 (used in the following systems: Feedwater, Main Generator and Auxiliaies, and Main Turbine and Auxiliaries).

h. September 2005 Revision 1 SRP Section 3.2.2.2.9 addresses line item E-42 for loss of material in steel piping in a soil environment due to general, pitting, and crevice corrosion.

MIC was added to the aging mechanisms in the September 2005 Revision 1 SRP. This item is addressed in the Oyster Creek LRA in the ESF section (E-42, Table 3.2.1-12, LRA Section 3.2.2.2.8.3).

The Buried Piping Inspection program B.1.26 addresses aging effects from the MIC aging mechanism.

Reference the Reconciliation document, Attachment 5 Item No. 17. The September 2005 Revision 1 GALL now specifies verification that at least one focused or opportunistic inspection in historically or suspected susceptible areas be performed prior to the period of extended operation but within the past 10 years. This is addressed in the Oyster Creek LRA description of the Buried Piping Inspection program B.1.26. Reference the Reconciliation document:, Attachment 1, OC Program No. B.1.26.

Enclosure Page 37 of 39 Itcen No AMR-344 Topic: Aging Management of Auxiliary Systems Ouestion: 3.3-11 In Table 3.3.2.1.18 of the OCGS LRA, several AMR line items are included for copper or copper alloy components in an auxiliary steam (internal) environment for which loss of material due to pitting or crevice corrosion is managed by one-time inspection alone. Please provide the justification for concluding that one-time inspection alone is sufficient for managing loss of material due to pitting or crevice corrosion for these AMR line items.Response: This is an error in the application identified in project open item #1554 and PassPort IR 00376714.04.18.

The Water Chemistry program, B.1.2, in conjunction with the One-Time Inspection program will manage the loss of material in these components.

Enclosure Page 38 of 39 Item No AMR-349 Topic: Buried Pipe Ouestion: GM-5A As a follow up question to AMR-241, based on review of the Table 2s for Sections 3.1 through 3.4, the Buried Piping Inspection program (AMP B.1.26) is credited to manage loss of material for piping and fittings exposed to soil for the following material/environment combinations.

a) Carbon steel/soil (service water system, emergency service water system, etc.), b) cast iron/soil (fire protection system), c) stainless steel/soil (heating and process steam system), d) bronze/soil (roof drains), and e) aluminum/soil (spent fuel pDol cooling system, condensate transfer system, etc.). For each of these material/environment combinations, please con"irm that at least one inspection has been, or will be performed during the 10-year period immediately prior to entering the license renewal period.Response: a) Carbon steel/soil ECR 05-00344 is scheduled to replace underground carbon steel Service Water piping in 1R21 (20(06).During this replacement the Service Water piping will be excavated and inspections of the external coating of the carbon steel Service Water piping will be conducted.

b) Cast iron/soil Buried cast iron components in the scope of license renewal are valves and fire hydrants in the Fire Protection system. These buried components are coated with coal tar and epoxy coating in the same fashion as -the buried carbon steel piping. A buried cast iron fire hydrant was replaced in 2003. The hydrant that was removed was found to have seat degradation and plugged drain holes, but there were no identified indications of external surface or coating degradation.

c) Stainless steel / soil The stainless steel piping in the scope of this program is potentially used in the Heating and Process Steam system. This system is in scope forl0 CFR 54.4(a)(2) spatial interaction only. Normally, buried pip's is not in scope for (a)(2) spatial interaction because leakage from a buried portion of pipe cannot spray onto safety related components.

However, this "Buried" Heating & Process Steam piping in scope is located in the pipe vault. The pipe vault is primarily an outdoor air environment, but is conservatively considered buried because it can accumulate debris. The Buried Piping Inspection program includes an enhancement to inspect the piping inside this vault in conjunction with the preventative maintenance activity to inspect the vault and pump out accumulated water every 6 months. This activity will be performed within the 10-year period immediately prior to entering the license renewal period. See Section 3.3 of program basis document PBD-AMP-B.1.26, Buried Piping Inspection.

Enclosure Page 39 of 39 d) Bronze/soil The buried bronze components in the scope of this program are threaded fittings < 2.5 inches, potentially used in the Roof Drains and Overboard Discharge system. These buried fittings are coated with coal tar and epoxy coating in the same fashion as the buried carbon steel piping. These fittings are associated with an unpressurized drain system whose function is to drain water in the event of a fire protection water system initiation.

As such, the pressure boundary integrity is not critical so long as the fitting does not become blocked such that drainage is prevented.

These fittings will not be specifically identified for excavation and inspection, as they are adequately addressed by the inspections that have been or will be performed for the buried carbon steel piping external coating inspection.

e) Aluminum/soil AR A2116126 is scheduled to inspect the coatings on two underground aluminum condensate transfer lines in 2006.Upon entering the period of extended operation, focused inspection of buried piping and components will be performed within ten years, unless an opportunistic inspection occurs within this ten-year period. The inspections will include at least one carbon steel, one aluminum and one cast iron pipe or component.

In addition, fo- each of these materials, the locations selected for inspection will include at least one location where the pipe or component has not been previously replaced or recoated, if any such locations remain.The stainless steel piping in the vault will continue to be periodically inspected, and the bronze material is addressed by the buried carbon steel pipe coating inspections, as described above.